As filed with the Securities and Exchange Commission on July 20, 2007

Registration No. 333-142430

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

AMENDMENT NO. 4

TO

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

REX ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	1311	20-8814402
(State or other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1975 Waddle Road

State College, Pennsylvania 16803

(814) 278-7267

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Christopher K. Hulburt

1975 Waddle Road

State College, Pennsylvania 16803

(814) 278-7267

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Charles L. Strauss, Esq. Fulbright & Jaworski L.L.P. Fulbright Tower 1301 McKinney, Suite 5100 Houston, Texas 77010 Telephone: (713) 651-5535 Facsimile: (713) 651-5246 James M. Prince Vinson & Elkins L.L.P. 1001 Fannin, Suite 2500 Houston, Texas 77002 Telephone: (713) 758-2222 Facsimile: (713) 758-2346

Approximate date of commencement of proposed sale to the public:    As soon as practicable after this registration statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act, check the following box.  ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission acting pursuant to said Section 8(a), may determine.

SUBJECT TO COMPLETION, DATED JULY 20, 2007

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

14,670,000 Shares

Rex Energy Corporation

Common Stock

This is an initial public offering of 14,670,000 shares of the common stock of Rex Energy Corporation. We are selling 9,200,000 shares of common stock, and the selling stockholders are selling 5,470,000 shares of common stock. We will not receive any of the proceeds from the shares of common stock sold by the selling stockholders.

Prior to this offering, there has been no public market for our common stock. We anticipate the initial public offering price will be between $11.00 and $13.00 per share. We have applied to list our common stock on The NASDAQ Global Market, subject to notice of official issuance, under the symbol “REXX”.

Investing in our common stock involves risks. See “ Risk Factors” beginning on page 19 to read about factors you should consider before buying shares of our common stock.

	Per share	Total
Price to the public	$	$
Underwriting discount(1)	$	$
Offering proceeds, before expenses, to Rex Energy Corporation	$	$
Offering proceeds, before expenses, to selling stockholders	$	$

(1) Excludes an aggregate structuring fee payable to KeyBanc Capital Markets Inc. equal to 0.5% of the gross proceeds of this offering, including proceeds from any exercise of the underwriters’ over-allotment option as described below, in consideration of advice rendered by KeyBanc Capital Markets Inc. regarding the structure of this offering and Rex Energy Corporation.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is accurate or complete. Any representation to the contrary is a criminal offense.

We have granted an over-allotment option to the underwriters. Under this option, the underwriters may elect to purchase a maximum of 2,200,500 additional shares within 30 days following the date of this prospectus to cover any over-allotments.

The underwriters expect to deliver the shares of common stock to investors on or about                     , 2007.

KeyBanc Capital Markets

RBC Capital Markets

A.G. Edwards

Johnson Rice & Company L.L.C.

Pickering Energy Partners

                    , 2007

TABLE OF CONTENTS

PROSPECTUS SUMMARY	1
RISK FACTORS	19
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS	31
USE OF PROCEEDS	32
DIVIDEND POLICY	32
CAPITALIZATION	33
DILUTION	34
SELECTED HISTORICAL FINANCIAL AND OPERATING DATA	35
PRO FORMA COMBINED FINANCIAL DATA	40
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	48
BUSINESS	67
MANAGEMENT	91
THE REORGANIZATION TRANSACTIONS	109
PRINCIPAL AND SELLING STOCKHOLDERS	116
RELATED PARTY TRANSACTIONS, CONFLICTS OF INTEREST AND CERTAIN RELATIONSHIPS	121
DESCRIPTION OF CAPITAL STOCK	125
SHARES ELIGIBLE FOR FUTURE SALE	129
MATERIAL U.S. FEDERAL TAX CONSIDERATIONS FOR NON-U.S. HOLDERS OF COMMON STOCK	131
UNDERWRITING	134
LEGAL MATTERS	138
EXPERTS	138
WHERE YOU CAN FIND MORE INFORMATION	139
INDEX TO FINANCIAL STATEMENTS	F-1

You should rely only on the information contained in this prospectus or to which we have referred you. We have not, and the underwriters have not, authorized anyone to provide you with different information. This document may only be used where it is legal to sell these securities. You should assume that the information contained in this prospectus is accurate only as of the date of this prospectus.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in the prospectus. Because it is a summary, it does not contain all of the information that you should consider before investing in our common stock. You should read and carefully consider this entire prospectus before making an investment decision, especially the information presented under the heading “Risk Factors” and our combined financial statements, pro forma financial statements and the accompanying notes included elsewhere in this prospectus, as well as the other documents to which we refer you.

In this prospectus, we refer to certain companies—Douglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, New Albany-Indiana, LLC, PennTex Resources, L.P., PennTex Resources Illinois, Inc., Rex Energy Limited Partnership, Rex Energy II Limited Partnership, Rex Energy III LLC, Rex Energy IV, LLC, Rex Energy II Alpha Limited Partnership, Rex Energy Operating Corp. and Rex Energy Royalties Limited Partnership—collectively as the “Founding Companies.”

Simultaneously with the consummation of the offering made by this prospectus, Rex Energy Corporation, through a series of mergers and reorganization transactions, which we refer to collectively herein as the “Reorganization Transactions,” will acquire all of the operations of the Founding Companies. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation, together with the Founding Companies, after giving effect to the Reorganization Transactions described in this prospectus. Unless otherwise indicated, all share, per share and financial information set forth herein (i) have been adjusted to give effect to the Reorganization Transactions and (ii) assume no exercise of the underwriters’ over-allotment option.

We have provided definitions for some of the oil and natural gas industry terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” in Appendix B.

Rex Energy Corporation

We are an independent oil and gas company operating in the Illinois Basin, the Appalachian Basin and the southwestern region of the United States. We pursue a balanced growth strategy of exploiting our sizeable inventory of lower risk developmental drilling locations, pursuing our higher potential exploration drilling prospects and actively seeking to acquire complementary oil and natural gas properties. At December 31, 2006, our proved reserves, of which approximately 77% were proved developed, totaled approximately 14.5 million barrels of oil equivalents, or MMBOE, which were comprised of approximately 80% oil and had a reserve life index of approximately 14 years. At December 31, 2006, we operated approximately 2,150 wells, which represent approximately 95% of our total proved reserves. For the quarter ended March 31, 2007, we produced an average of 2,770 net BOE per day, comprised of approximately 81% oil and approximately 19% natural gas.

We are one of the largest oil producers in the Illinois Basin, with average net daily production of 2,127 barrels of oil per day in the first quarter of 2007. In addition, we also have acquired, or have an option to acquire, over 270,000 gross acres in southern Indiana, which we believe are prospective for New Albany Shale exploration and development. We are also developing an enhanced oil recovery project, or EOR project, in the Lawrence Field in Lawrence County, Illinois, which we refer to as our Lawrence Field ASP Flood Project.

In our Appalachian region, we averaged net production of approximately 2.2 MMcf of natural gas per day, while we averaged approximately 1.6 MMcfe net per day in our Southwestern region. In both regions, we have several active drilling projects.

Since 2004, we have completed 17 significant acquisitions in our core operating areas. Three of these consisted of acreage acquisitions in the Illinois Basin associated with our New Albany Shale projects for

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approximately $6.6 million. Fourteen of these consisted of producing properties, which as of March 31, 2007 have added approximately 13.2 MMBOE to our proved reserves, for approximately $92.3 million in acquisition costs, or an average cost per proved BOE of $6.99. The following table summarizes our producing property acquisitions since 2004:

	Producing Property Acquisitions
Year	Approx. Purchase Price (in millions)		Proved Reserves (MMBOE)	Average Cost per Proved BOE
2004	$	7.0	3.1	$	2.25
2005		17.6	3.6		4.87
2006		65.7	6.4		10.33
2007		2.0	0.1		20.00
	$	92.3	13.2	$	6.99

Our total revenues for the first quarter of 2007 were $12.9 million, before the effects of oil and gas financial derivatives, and $13.1 million after the effects of realized oil and gas financial derivatives. Revenues were derived from $10.9 million in oil sales, $1.9 million in natural gas sales, $265,000 in realized gains from derivatives and $100,000 in other transportation and water disposal revenues.

In the three years ended December 31, 2006, we drilled 126 gross (61 net) wells, 95% of which are currently producing, including 68 gross (40 net) wells in the 12 months ended December 31, 2006.

The following table shows selected data concerning our production, proved reserves and undeveloped acreage in our three operating regions for the periods indicated.

Basin/Region	First Quarter 2007 Average Daily BOE	Total Proved MMBOE (As of December 31, 2006)	Percent of Total Proved MMBOE		PV-10 (As of December 31, 2006) (in Millions)(1)		Total Net Undeveloped Acres (As of May 31, 2007)(2)
Illinois Basin	2,127	10.8	74	%	$	165.5	93,031	(3)
Appalachian Basin	371	1.7	12	%		17.7	5,151
Southwestern Region	272	2.0	14	%		17.1	966
Total	2,770	14.5	100	%	$	200.3	99,148

(1) Represents the present value, discounted at 10% per annum (PV-10), of estimated future net revenue before income tax of our estimated proved reserves. PV-10 is a non-GAAP financial measure because it excludes the effects of income taxes and asset retirement obligations. PV-10 should not be considered as an alternative to the pro forma standardized measure of discounted future net cash flows as defined under GAAP. At December 31, 2006, our pro forma standardized measure was $132.1 million. For an explanation of why we show PV-10 and a reconciliation of PV-10 to the pro forma standardized measure of discounted future net cash flows, please read “Selected Historical Financial and Operating Data—Non-GAAP Financial Measures.” Please also read “Risk Factors—Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.”

(2) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes proved reserves.

(3) Includes an option to acquire approximately 70,000 gross (20,900 net) acres in Indiana for $25.00 per net acre.

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Summary of Capital Expenditures

We have established a capital budget of approximately $37.9 million, excluding acquisitions, for 2007 and approximately $32.9 million for 2008. We intend to use a substantial portion of our proceeds from the offering to retire all of our debt and for working capital. We have received a commitment to establish a new senior credit facility with an initial borrowing capacity of $75 million for working capital and general corporate purposes including acquisitions. We believe that our projected cash flows from our proved reserve base and availability under our proposed new senior credit facility will enable us to fund our planned capital expenditures in 2007 and 2008. We expect to enter into this new senior credit facility shortly after the completion of this offering.

The following table summarizes information regarding our historical 2006 and our estimated 2007 and 2008 capital expenditures. The estimated 2007 capital expenditures shown are preliminary full year estimates, and include approximately $13.6 million spent from January 1, 2007 through May 31, 2007, which includes approximately $4.4 million in acquisitions. The estimated capital expenditures are dependent on a number of factors, including industry conditions and our drilling success, and are subject to change. The historical 2006 capital expenditures below include capital expenditures for acquisitions and leasing. In addition, the estimates for 2007 include $2.0 million for acquisitions and $2.4 million for leasing, reflecting acquisitions and leases made or entered into prior to May 31, 2007. We do not attempt to budget for future investments in acquisitions or leasing.

	Year Ending December 31,
	2006 (historical)		2007 (estimated)		2008 (estimated)
	(in millions)
Capital expenditures
Illinois Basin Conventional Oil Operations	$	7.6	$	10.0	$	5.1
Illinois Basin ASP Flood Project		0.1		3.5		0.7
New Albany Shale Project		2.5		7.3		17.9
Appalachian Basin Operations		2.3		3.5		3.3
Southwestern Region Operations		1.1		13.6		5.9
Acquisitions of proved oil and gas properties		67.7		2.0		—
Acquisitions and leasing of undeveloped properties		14.3		2.4		—
Total capital expenditures	$	95.6	$	42.3	$	32.9

Our Competitive Strengths

We believe our historical success is, and future performance will be, directly related to the following combination of strengths that we believe will enable us to implement our strategy:

Significant Production Growth Opportunities: We have several projects and properties that we believe are capable of resulting in significant proved reserves and production growth. These include:

• Our Alkali-Surfactant-Polymer Flood project in the Lawrence Field, one of the largest fields in the Illinois Basin (please read “—Our Active Projects—Illinois Basin Projects—The Lawrence Field ASP Flood Project”);

• Our large New Albany Shale acreage position of over 270,000 gross acres in southern Indiana (please read “—Our Active Projects—Illinois Basin Projects—The Illinois Basin New Albany Shale Project”);

• Our natural gas drilling opportunities in the Appalachian Basin on over 50,000 gross acres in Pennsylvania;

• Our oil drilling opportunities in the Illinois Basin, including 210 proved undeveloped drilling locations in Illinois and Indiana; and

• Our oil and gas development projects in the Permian Basin.

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Market Leader in the Illinois Basin: We are one of the largest oil producers and a market leader in the Illinois Basin, which enables us to realize a current premium over the basin posted prices on our oil production and a competitive cost structure due to economies of scale, and provides us with a unique local knowledge of the basin, which we believe will allow us to continue to pursue strategic acquisitions in the basin.

Experienced Management Team with a Proven Track Record: We have significant technical and management experience in our core operating areas. Our technical team of geologists and engineers averages over 20 years of experience, primarily in the Illinois, Appalachian and Permian Basins. We believe the experience and capabilities of our management team have enabled us to build a high quality asset base of proved reserves and growth projects, both organically and through selective acquisitions.

Financial Flexibility: We plan to maintain a conservative financial position. We expect to use a portion of the proceeds from the offering to retire all senior debt facilities of the Founding Companies, which will provide us with an initial debt-free balance sheet and enable us to utilize our operating cash flows to pursue our planned growth through our exploration and development activities. In addition, we plan to establish shortly after the offering a new senior credit facility with an expected initial borrowing capacity of $75 million to provide additional financial flexibility.

Incentivized Management Ownership: After giving effect to the Reorganization Transactions and the offering described in this prospectus, our directors and officers will beneficially own approximately 45.7% of our outstanding common stock, which we believe aligns their interests with those of our stockholders.

Business Strategy

Our strategy is to increase stockholder value by profitably increasing our reserves, production, cash flow and earnings. The following are key elements of our strategy:

Employ Technological Expertise: We intend to utilize and expand the technological expertise that has enabled us to achieve a drilling completion rate of approximately 95% during the last three years and has helped us improve operations and enhance field recoveries. We intend to apply this expertise to our proved reserve base and our development projects.

Develop Our Existing Properties: We will continue to focus on developing our asset base in each of our operating basins including:

• Our Lawrence Field ASP Flood Project in Illinois;

• Our New Albany Shale resource play with over 270,000 gross acres; and

• Our inventory of over 500 proved undeveloped locations and proved developed non-producing wells.

Pursue Strategic Acquisitions and Joint Ventures: We expect to continue to acquire and lease additional natural gas and oil properties in our core areas of operation. We believe that our strong history of acquisitions, leading position in the Illinois Basin and technical expertise will help us continue to pursue strategic acquisitions and joint ventures.

Focus on Operations: We expect to focus our future acquisition and leasing activities on properties where we have a significant working interest and can operate the property to control and implement the planned exploration and development activity.

Reduce Per Unit Operating Costs Through Economies of Scale and Efficient Operations: As we continue to increase our oil and natural gas production and develop our existing properties, we believe that our per unit production costs will benefit from increased production in lower cost operations and through better utilization of our existing infrastructure over a larger number of wells.

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Our Active Projects

In addition to our proved reserves, we have assembled an extensive inventory of non-proved projects.

Illinois Basin Projects

Lawrence Field ASP Flood Project. We are implementing an alkaline-surfactant-polymer, or ASP, flood in the Lawrence Field in Lawrence County, Illinois. The Lawrence Field is believed to have produced more than 400 million barrels of oil, representing approximately 40% of the original oil in place in the field, since its discovery in 1906. We own and operate approximately 13,500 net acres of the Lawrence Field and our properties account for approximately 85% of the current total gross production from the field. During the 1980s, surfactant polymer flood projects implemented in the Lawrence Field demonstrated increases in ultimate oil recoveries by 10% to 30%. These previous surfactant polymer floods were deemed technically successful, but were discontinued because the development costs were not economic given prevailing oil prices at the time.

The ASP technology, which is designed to wash residual oil from the reservoir rock and improve the existing waterflood’s ability to sweep the residual oil, has been successfully implemented in several fields around the world and has been shown to achieve ultimate oil recoveries similar to those demonstrated in the older surfactant polymer floods in the Lawrence Field but at significantly lower chemical costs. This cost reduction is achieved through the addition to the chemical mixture of an alkali solution which substantially reduces the amount of surfactant, the most expensive chemical component used in the flood.

We plan to initiate injection of the ASP chemicals in two pilot test areas in the field in 2007. If either of these two pilots is successful, we plan to implement a broad ASP flood program within the 13,500 net acres of the field that we currently own and operate, commencing in 2008. While we are encouraged by our initial laboratory report, our EOR project in the Lawrence Field is not a proved project nor are any of the potential reserves from this project considered proved at this time.

New Albany Shale. As of May 31, 2007, we had acquired 201,000 gross (67,400 net) acres, and we have an option to acquire an additional 70,000 gross (20,900 net) acres in southern Indiana which we believe is prospective for New Albany Shale exploration and development. Although limited gas production from vertical wells in the New Albany Shale has occurred for many years, interest in the potential of the New Albany Shale has recently increased due to the application of horizontal drilling techniques that can intersect numerous vertical fractures in the shale, significantly increasing the amount of reservoir contacted by each well-bore. We believe the average well spacing in our acreage area will be 320 acres.

While New Albany Shale horizontal drilling is still in its exploratory stage, it has attracted the attention of several oil and gas companies that are currently drilling in southern Indiana and northern Kentucky, including Chesapeake Energy Corporation (NYSE: CHK), Quicksilver Resources Inc. (NYSE: KWK), Aurora Oil & Gas Corporation (AMEX: AOG), Samson Investment Company, Noble Energy, Inc. (NYSE: NBL) and El Paso Corporation (NYSE: EP).

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As of May 31, 2007, our New Albany Shale acreage is located in the following project areas:

Project Name	Counties	Average Working Interest		Approximate Total Gross Acres	Operator
Eastern Knox	Knox/Sullivan	40.0	%	18,000	Rex Energy
Western Knox	Knox/Sullivan	26.8	%	40,800	Rex Energy
Wabash	Greene/Clay/Owen/ Sullivan	29.1	%	113,265	Aurora Oil & Gas Corp.
Wabash (Option Acres)(1)	Washington/Lawrence/ Jackson /Orange	29.8	%	70,000	Aurora Oil & Gas Corp.
Bogard	Greene	10.1	%	8,735	El Paso Exploration & Production Company
Other Areas Held by Production	Posy/Gibson/ Gallatin (IL)	65.7	%	20,700	Rex Energy
Total				271,500

(1) In addition to the acres we currently own in the Wabash AMI, we own an option to acquire a 29.8% working interest (26.0% average net revenue interest) in approximately 70,000 gross (20,900 net) acres in Washington, Lawrence, Jackson and Orange Counties, Indiana, from Aurora Oil & Gas Corporation for $25.00 per net acre until August 1, 2007. Aurora Oil & Gas Corporation is the operator within the Wabash AMI.

Since February 2006, we have participated in 11 gross New Albany Shale wells, four of which we operate, in Greene County and Knox County, Indiana, which are currently being tested to determine whether they will be economical to complete and produce and to design stimulation procedures, if required.

Appalachian Basin Projects

Westmoreland County. In Westmoreland County, Pennsylvania, we own a 100% working interest in approximately 73 natural gas wells and 2,100 undeveloped acres with total proved reserves of 1,180 MBOE. We believe that we can drill an additional 125 to 150 wells in the field on our current acreage. Since acquiring the field in 2004, we have drilled and completed 20 wells, with a 100% success rate. These wells target the Bradford Sands at a depth of approximately 4,000 feet at an average cost of approximately $192,000 per well.

Fayette County. In Fayette County, Pennsylvania, we own approximately 22,000 gross (7,330 net) acres, of which approximately 12,900 gross (3,000 net) acres are undeveloped. As of December 31, 2006, we owned 122 producing gas wells on our Fayette County properties with total proved reserves of 192 MBOE. Great Lakes Energy, a wholly owned subsidiary of Range Resources Corporation, is the operator on approximately 5,000 gross undeveloped acres in which we own an average working interest of 16%. This area has historically been drilled on 40 acre spacing. During 2006, we participated in the drilling and completion of 24 wells and one dry hole (a 96% success rate) in this project area at an average cost of approximately $222,000 per well.

Marcellus Shale Potential. Our properties in Western Pennsylvania are located in areas where active exploration for the Marcellus Shale, by companies such as Range Resources Corporation (NYSE:RRC) and Atlas Energy Resources, LLC (NYSE: ATN), is currently occurring. The Marcellus Shale is a black, organic rich shale formation located at depths between 7,000 and 8,500 feet and ranges in thickness from 100 to 150 feet in Western Pennsylvania. Our acreage in Western Pennsylvania totals 53,000 gross acres (38,600 net acres), 87% of which is currently held by production. As the vast majority of our acreage in Western Pennsylvania is held by production, we expect to test several areas of our acreage after this emerging play has been further tested and refined in our area by other operators.

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Southwestern Region Projects

Allison Field. We own a 49.8% interest in and operate the Allison Field in Terrell County, Texas. As of December 31, 2006, the field was comprised of 15 producing wells with 154 MBOE of proved reserves. Our leasehold covers 4,480 gross acres in the field. We have identified several recompletion and workover opportunities in the field, as well as drilling potential in both the Canyon and Leonard Sands.

Azalea Field. We own a 99.5% working interest in and operate the Azalea Field in Midland County, Texas. As of December 31, 2006, our properties in the field included 16 gross producing wells with 345 MBOE of proved reserves. Our leasehold covers approximately 1,900 gross acres in the field. We have identified several development opportunities, including the perforation of the Grayburg zone which we believe, based on well log analysis, can be productive in several of the wells. We plan to install a waterflood of the Grayburg reservoir in the field in 2008.

East Carlsbad Field. We own an average 33% working interest in the East Carlsbad Field in Lea and Eddy Counties, New Mexico. As of December 31, 2006, our properties in the field included 13 gross producing wells, 10 of which we operate, with 522 MBOE of proved reserves. Our leasehold covers approximately 2,400 gross acres. We have identified several potential improvements in the field, including the workover of several wells, testing the potential of increased density drilling of the Cisco/Wolfcamp formations and recompleting certain wells to the Atoka formation. If the Atoka recompletion is successful, we believe we could drill several offset wells on our acreage.

Pecan Station Prospect. We own a 100% working interest in 480 acres in the Pecan Station Field in Tom Green County, Texas, which we refer to as the Pecan Station prospect. We plan to drill a new well on the acreage to test the Strawn Lime in 2007, and if the initial well is successful, we intend to drill an additional three to four wells on our acreage in the prospect area in 2007 and 2008.

Bison Prospect. We own a 100% working interest in 240 acres in Garza County, Texas, which we refer to as the Bison prospect. The Bison prospect is based upon re-entering a well on the acreage that was drilled in 1981 to the Ellenburger formation. We intend to commence this re-entry in 2007 to test three prospective objectives: the Spraberry formation at 5,100 feet and the Strawn Lime ‘A’ and ‘B’ formations found at 7,450 feet and 7,500 feet, respectively. If this re-entry results in successful commercial production from either of the Spraberry or Strawn formations, we intend to drill an additional six to eight wells on our acreage in 2007 and 2008.

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Our Reserves

Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm, evaluated our reserves on a consolidated basis as of December 31, 2006, a summary of which is attached to this prospectus as Appendix A. All of our reserves are located within the continental United States. Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of additional exploration and development, prices of oil and natural gas and other factors. Please read “Risk Factors—Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.” You should also read the notes following the table below and our financial statements for the year ended December 31, 2006 included elsewhere in this prospectus in conjunction with the following reserve estimates.

	As of December 31, 2006
Estimated Proved Reserves(1)
Gas (Bcf)		17.2
Oil (MMBbls)		11.6
Total proved reserves (MMBOE)(2)		14.5
Total proved developed producing reserves (MMBOE)		9.6
PV-10 Value (in millions)(3)
Proved developed producing reserves	$	143.9
Proved developed non-producing reserves		24.1
Proved undeveloped reserves		32.3
Total PV-10 value	$	200.3
Pro Forma Standardized Measure (in millions)(4)	$	132.1

(1) The estimates of reserves in the table above conform to the guidelines of the SEC. Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our financial derivative activities. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and present value are based on various assumptions, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

(2) We converted natural gas to barrels of oil equivalent at a ratio of one barrel to six Mcf.

(3) Represents the present value, discounted at 10% per annum (PV-10), of estimated future net revenue before income tax of our estimated proved reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on economic conditions prevailing as of December 31, 2006. The estimated future production is priced at December 31, 2006, without escalation, using $57.75 per bbl and $5.635 per MMBtu, and adjusted by lease for transportation fees and regional price differentials. The estimated present value of proved reserves does not give effect to indirect expenses such as general and administrative expenses, debt service and future income tax expense, asset retirement obligations or to depletion, depreciation and amortization. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional

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analysts and sophisticated investors in evaluating oil and natural gas companies. For an explanation of why we show PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flow, please read “Selected Historical Financial and Operating Data—Non-GAAP Financial Measures.” Please also read “Risk Factors—Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.”

(4) Because each of the Founding Companies was a flow-through entity for state and federal tax purposes, our historical standardized measure does not deduct state or federal taxes. This differs from our pro forma standardized measure, which deducts state and federal taxes.

Recent Events

On April 17, 2007, Rex Energy II Limited Partnership, one of the Founding Companies, acquired a 52.3% working interest in the Dare I Cook Field and an 83.7% working interest in the Dare I Hope Field in Concho County, Texas from Ultra Oil & Gas, Inc. and certain other non-operated working interest owners for $890,000. We are now the operator of the fields. Prior to the acquisition, Douglas Oil & Gas, one of the Founding Companies, owned a 32% non-operated working interest in the Cook Field. As of December 31, 2006, there were 10 producing oil wells, 8 water injection wells, 3 water supply wells and 8 shut-in wells on the fields with total production of 50 gross barrels of oil per day. The fields have produced approximately 1.4 million barrels to date since their discovery in 1996. To improve operations and production in the field, we intend to redesign the current waterflood pattern, implement a new chemical program in the field to reduce scale buildup and test the use of polymer gels to increase sweep efficiency in the fields.

On April 27, 2007, we acquired 100% of the New Albany Shale formation rights underlying the fields we acquired in our Team Energy acquisition in 2006 for $750,000 totaling approximately 10,000 acres. The acreage is located in Posey and Gibson Counties, Indiana, and Lawrence County, Illinois. Prior to the acquisition, we owned the mineral leasehold rights to all other depths on the properties. We are the operator of the properties.

On May 24, 2007, we acquired a 40% working interest in certain undeveloped oil and gas leases covering approximately 18,000 gross acres located in Knox, Davies, Sullivan and Greene Counties in Indiana. The acreage acquired is contiguous to our Knox County acreage that we are currently drilling for the New Albany Shale. We acquired the interests from HAREXCO, Inc., an Illinois corporation doing business in Indiana under the assumed name of Harris Energy Company, for a purchase price of approximately $1.1 million. In connection with this sale, Harris Energy reserved from the 40% working interest conveyed to us a 4% overriding royalty interest and a 10% back-in-after-payout working interest in the first five net wells drilled on the conveyed properties or any other properties in the area that we subsequently acquire from Harris Energy. We are the operator of the properties within the area of mutual interest. In addition, we also agreed to purchase from Harris Energy a 40% working interest in certain undeveloped oil and gas leasehold interests covering up to 5,878 net acres located in Knox County. Pursuant to the agreement between the parties, we are obligated to purchase an interest in only those oil and gas leases that Harris Energy acquires on or before August 22, 2007.

Risk Factors

Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile oil and natural gas prices and other material factors discussed more fully in the “Risk Factors” section of this prospectus. In particular, the following considerations may offset our competitive strengths or have a negative effect on our business strategy, as well as activities on our properties, and could cause a decrease in the price of our common stock and result in a loss of a portion or all of your investment:

• Our use of EOR methods in our ASP project or our use of horizontal drilling might not be not be effective at increasing our levels of production;

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• Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operation;

• Concentrations of reserves, concentration of client revenue, our derivative activities, our assumptions used to determine our estimated reserves and general laws, regulations and environmental matters could also affect our financial performance and operations.

Please read “Risk Factors” in its entirety.

Our Offices

Our principal executive offices are located at 1975 Waddle Road, State College, PA 16803 and our telephone number is 814-278-7267. Our regional offices are located in Canonsburg (Pittsburgh), Pennsylvania, Midland, Texas and Bridgeport, Illinois. Our website is www.rexenergy.com. Information contained on our website, or on any other website, does not constitute a part of this prospectus.

Financial Statement Presentation

We have included in this prospectus audited interim financial statements of the Company as of March 31, 2007 and for the period from inception to March 31, 2007. We also have included in this prospectus annual audited financial statements for each of the individual Founding Companies as of December 31, 2006 and 2005 and for each of the three years (or from inception) in the period ended December 31, 2006, except for Rex Energy Limited Partnership as discussed below.

Because the Company is succeeding to the businesses of each of the Founding Companies, we have designated the Founding Companies on a combined basis as our accounting predecessor. As such, we have included in this prospectus annual audited combined financial statements of the Founding Companies as of December 31, 2006 and 2005 and for each of the three years in the period ended December 31, 2006 and unaudited interim combined financial statements of the Founding Companies as of March 31, 2007 and for each of the three month periods ended March 31, 2007 and 2006. The audited annual statements and unaudited interim statements include combining tables that detail the amounts from each individual Founding Company.

Although the accounts and transactions of Rex Energy Limited Partnership are included in the audit of the combined financial statements of the Founding Companies, we have not included individual annual audited financial statements for Rex Energy Limited Partnership because this partnership’s only significant asset for each of the three years in the period ended December 31, 2006 was an equity investment in Douglas Oil & Gas Limited Partnership which accounted for over 90% of the partnership’s assets and income or loss in each period. We have not included financial statements for Rex Energy I, LLC, a wholly owned subsidiary of the Company, as this entity was formed in April 2007 and has not conducted any business as of the date of this prospectus. We have not included financial statements for PennTex Energy, Inc. because this company’s sole asset is its one percent general partnership interest in PennTex Resources, L.P.

We have included in this prospectus audited statements of revenues and direct operating expenses of significant acquisitions completed by certain of the Founding Companies during the three year period ended December 31, 2006.

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The Reorganization Transactions

Historically, we have conducted our operations through several operating partnerships under the common control of Lance T. Shaner, our Chairman, through his direct and indirect ownership interests and other contractual arrangements, as well as under common management of Rex Operating. Pursuant to the Reorganization Transactions, we will combine the operations of these partnerships and companies under a holding company structure upon completion of this offering. Rex Energy Corporation will serve as the parent holding company for this structure.

PennTex Resources, L.P., as the earliest Founding Company formed and by virtue of being wholly owned by Lance T. Shaner, will be considered the accounting acquirer in the transactions by which the Company will acquire all of the operations of the Founding Companies. As such, the acquisition of interests in the Founding Companies not owned by Mr. Shaner will be accounted for as a purchase, and the excess of the purchase price over historical book value will be added to the balance sheet of the Company. The economic interests in the Founding Companies not owned by Mr. Shaner are presented as minority interests in our combined financial statements.

The following table shows the level of ownership owned by Mr. Shaner, which is represented in the combined financial statements of our Founding Companies, and the level of minority interests of each of the Founding Companies. The interests listed in the following table as minority interests are the economic interests in these companies that are not owned by Mr. Shaner and that have been presented in our financial statements as minority interests.

		Mr. Shaner’s Interest		Minority Interest(1)
Douglas Oil & Gas Limited Partnership	“Douglas Oil & Gas”	13.70	%	86.30	%
Douglas Westmoreland Limited Partnership	“Douglas Westmoreland”	13.70	%	86.30	%
Rex Energy Royalties Limited Partnership	“Rex Royalties”	5.16	%	94.84	%
Midland Exploration Limited Partnership	“Midland”	2.52	%	97.48	%
New Albany-Indiana, LLC	“New Albany”	40.04	%	59.96	%
PennTex Resources Illinois, Inc.	“PennTex Illinois”	100.00	%	0.00	%
PennTex Resources, L.P.	“PennTex Resources”	100.00	%	0.00	%
Rex Energy Limited Partnership	“Rex I”	22.28	%	77.72	%
Rex Energy II Limited Partnership	“Rex II”	11.10	%	88.90	%
Rex Energy II Alpha Limited Partnership	“Rex II Alpha”	0.00	%	100.00	%
Rex Energy III LLC	“Rex III”	46.50	%	53.50	%
Rex Energy IV, LLC	“Rex IV”	50.00	%	50.00	%
Rex Energy Operating Corp.	“Rex Operating”	60.00	%	40.00	%

(1) Represents the economic interests in these companies not owned by Mr. Shaner, which are represented as minority interests in the combined financial statements of our Founding Companies.

We intend to merge Douglas Oil & Gas, Douglas Westmoreland, Midland, New Albany, Rex I, Rex II, Rex III, Rex II Alpha and Rex Royalties with and into Rex Energy I, LLC, with Rex Energy I, LLC being the surviving entity of each of such mergers. Mr. Shaner controls Douglas Oil & Gas, Douglas Westmoreland, Midland, Rex I, Rex II, Rex II Alpha and Rex Royalties through his direct ownership and control of the general partners of these limited partnerships. Mr. Shaner controls New Albany through his control of the managing member of the company. Mr. Shaner controls Rex III through his indirect control of the voting interests of the company. Each of the holders of the equity interests of such entities will receive for his, her or its equity interests in such entity a specified number of shares of our common stock based upon an exchange ratio that has been agreed to among us and the equity interest holders of such entities. Following completion of the Reorganization Transactions, Rex Energy I, LLC will continue as our wholly owned subsidiary.

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In addition, each of the holders of the equity interests of PennTex Resources Illinois, Inc. (“PennTex Illinois”), which is wholly owned by Mr. Shaner, Rex Energy IV, LLC (“Rex IV”), which is 50% owned by Mr. Shaner and which Mr. Shaner controls through his control of the board of managers, and Rex Energy Operating Corp. (“Rex Operating”), which is 60% owned by Mr. Shaner, will exchange his, her or its equity interests in such entity for a specified number of shares of our common stock based upon an exchange ratio that has been agreed to among us and the equity interest holders of such entities and each of such entities will become our wholly owned subsidiaries. Mr. Shaner, who owns 100% of the outstanding capital stock of Penn Tex Energy, Inc. (“Penn Tex Energy”), the general partner of PennTex Resources, L.P. (“PennTex Resources”), will exchange all of his shares of Penn Tex Energy for a specified number of shares of our common stock based upon an exchange ratio that has been agreed to between us and Mr. Shaner, and Penn Tex Energy will become our wholly owned subsidiary. Mr. Shaner, who is the sole limited partner of PennTex Resources, will exchange his limited partner interests in PennTex Resources for a specified number of shares of our common stock based upon an exchange ratio that has been agreed to among us and Mr. Shaner, and we will become the sole limited partner of PennTex Resources.

The consummation of the Reorganization Transactions is conditioned upon the consummation of this offering. For more information, please read “The Reorganization Transactions.”

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The following diagram depicts our organizational structure after giving effect to the Reorganization Transactions and this offering:

(1) Includes shares owned by Lance T. Shaner, Shaner Family Partners Limited Partnership, RexGuard, LLC, Shaner & Hulburt Capital Partners Limited Partnership and The Lance T. Shaner Irrevocable Grandchildren’s Trust II, which Mr. Shaner effectively controls. Mr. Shaner disclaims beneficial ownership of all equity interests of these entities, other than those which he owns directly under his name.

(2) Includes shares held by management (other than the Shaner Group). These shares held by management represent 14.2% of our outstanding shares.

(3) Reflects the merger of Douglas Oil & Gas, Douglas Westmoreland, Midland Exploration, New Albany, Rex I, Rex II, Rex III, Rex II Alpha and Rex Royalties with and into Rex Energy I, LLC pursuant to the Reorganization Transactions.

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The Offering

Common stock offered by us 9,200,000 shares (or 11,400,500 shares if the underwriters exercise their over-allotment option in full)

Common stock offered by selling stockholders 5,470,000 shares

Common stock to be outstanding immediately after completion of this offering(1)(2) 31,194,702 shares (or 33,395,202 shares if the underwriters exercise their over-allotment option in full)

Over-allotment option granted by us 2,200,500 shares

Proposed Nasdaq Global Market symbol “REXX”

Use of proceeds We expect to receive net proceeds from the sale of shares offered by us of approximately $101.9 million, based on an assumed offering price of $12.00 per share (the mid-point of the price range set forth on the cover of this prospectus), after deducting estimated offering expenses of $1.3 million remaining unpaid as of May 31, 2007, and underwriting discounts and commissions of approximately $7.2 million. We intend to use our net proceeds from this offering to retire all of the senior debt facilities and other notes payable to unrelated parties of the Founding Companies, totaling approximately $101.1 million as of the date hereof and the remainder to fund a portion of our expected 2007 capital expenditures and general corporate purposes, including for working capital. If the underwriters exercise their over-allotment option in full, we estimate that the net proceeds to us will increase by approximately $24.7 million after deducting underwriting discounts and commissions. We intend to use any net proceeds from the exercise of the over-allotment option to fund an additional portion of our expected 2007 capital expenditures and for other general corporate purposes. We will not receive any proceeds from the sale of shares of our common stock by the selling stockholders. See “Use of Proceeds.”

Dividend policy We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the future.

Risk factors Investing in our common stock involves certain risks. You should carefully consider the risk factors discussed under the heading “Risk Factors” beginning on page 19 of this prospectus before deciding to invest in our common stock.

(1) The number of shares of common stock to be outstanding after this offering excludes shares of common stock reserved for issuance under our 2007 Long-Term Incentive Plan, none of which have been granted. Please read “Management—2007 Long-Term Incentive Plan.”

(2) Represents 21,994,702 shares issued to the equity interest holders of the Founding Companies in the Reorganization Transactions (including the shares offered by the selling stockholders in this offering) and the 9,200,000 shares to be issued and sold by us in this offering.

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Summary Financial Data

The following table shows the summary combined financial data of the Founding Companies as of and for each of the periods indicated. The combined financial statements of the Founding Companies present historical combined financial data as of December 31, 2006 and 2005 and March 31, 2007, and for each the three years ended December 31, 2006 and the three months ended March 31, 2007 and 2006. The historical combined financial statements as of December 31, 2006 and 2005 and for each of the three years ended December 31, 2006 are derived from the historical audited financial data of the Founding Companies. The historical combined financial statements as of March 31, 2007 and for the three months ended March 31, 2007 and 2006 are derived from the historical unaudited financial data of the Founding Companies. As each of the Founding Companies was taxed as a partnership for each of the years indicated for federal and state income tax purposes, the following statements make no provision for income taxes.

The summary pro forma financial data as of and for the year ended December 31, 2006 are derived from the unaudited pro forma financial statements of Rex Energy Corporation included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain transactions had taken place on December 31, 2006, in the case of the pro forma balance sheet, or as of January 1, 2006, in the case of the pro forma statement of operations. These transactions include:

• the Reorganization Transactions;

• the initial public offering of our common stock and the application of the proceeds as described in “Use of Proceeds”; and

• the consummation of the following two acquisitions, each of which occurred in 2006:

• our acquisition in June 2006 of interests in approximately 177 producing oil wells and related infrastructure in Posey and Gibson Counties, Indiana and Lawrence County, Illinois for approximately $22.7 million from Team Energy, L.L.C. and certain of its affiliates and the acquisition of certain non-operating interests associated with the Team Energy leases for $1.2 million; and

• our acquisition in October 2006 of interests in the Lawrence, West Kenner and St. James fields in Illinois, and the El Nora field in Indiana for approximately $35.2 million from TSAR Energy II, L.L.C.

These adjustments are based on currently available information and certain estimates and assumptions, and, therefore, the actual effects of the transactions described above may differ from the effects reflected in the pro forma financial statements. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of these transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions.

You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our combined historical and pro forma financial statements and related notes included elsewhere in this prospectus. These summary combined historical and pro forma financial results may not be indicative of our future financial or operating results.

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The following table includes the non-GAAP financial measure of EBITDAX. For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Selected Historical Financial and Operating Data—Non-GAAP Financial Measures.”

	Three Months Ended March 31,						Year Ended December 31,									Pro Forma Three Months Ended March 31, 2007			Pro Forma Year Ended December 31, 2006
	2007			2006			2006			2005			2004
	(unaudited)			(unaudited)												(unaudited)			(unaudited)
	(In Thousands)
Statement of Operations
Operating Revenues
Oil and Natural Gas Sales	$	12,775		$	9,169		$	43,596		$	29,518		$	14,159		$	12,775		$	61,398
Realized Gain (Loss) from Derivatives		265			(1,390	)		(4,436	)		(7,929	)		(942	)		265			(4,436	)
Unrealized Gain (Loss) from Derivatives		(3,437	)		120			5,043			(5,541	)		(1,396	)		(3,437	)		5,043
Other Operating Revenues		100			127			470			270			697			100			470
Total Operating Revenue	$	9,703		$	8,026		$	44,672		$	16,317		$	12,519		$	9,703		$	62,475
Operating Expense:
Production and Lease Operating Expense		6,105			2,444			15,234			11,721			6,708			6,105			21,888
General and Administrative		1,982			844			6,212			3,789			2,229			1,982			7,620
Depletion, Depreciation and Amortization		4,073			2,065			11,222			3,320			2,039			7,320			24,696
Asset Impairment		585			—			—			107			3,024			585			—
Total Operating Expenses		12,745			5,353			32,669			18,937			14,000			15,993			54,204
Income (Loss) from Operations		(3,042	)		2,673			12,004			(2,620	)		1,481			(6,290	)		8,270
Other Income (Expense):
Interest Income		9			36			94			444			19			9			94
Interest Expense		(2,085	)		(766	)		(6,110	)		(1,697	)		(867	)		—			—
Gain on Sale or Disposal of Oil and Gas Properties		176			—			91			1,017			659			176			91
Other Income (Expense)		(44	)		(113	)		(132	)		216			(21	)		(44	)		(132	)
Total Other Income (Expense)		(1,943	)		(843	)		(6,057	)		(21	)		(211	)		142			53
Net Pre-Tax Income (Loss) Before Minority Interests	$	(4,985	)	$	1,829		$	5,947		$	(2,641	)	$	(1,692	)	$	(6,148	)	$	8,324
Minority Interest Share of Net Pre-Tax Income (Loss)		(2,728	)		921			2,134			2,304			(2,062	)		—			—
Net Pre-Tax Income (Loss) After Minority Interests		2,257			908			3,814			4,945			370			(6,148	)		8,324
Provision for Taxes		—			—			—			—			—			(2,478	)		3,354
Net Income	$	2,257		$	908		$	3,814		$	(4,945	)	$	370		$	(3,670	)	$	4,969
Other Financial Data:
EBITDAX (Before Minority Interests)	$	5,186		$	4,505		$	18,143		$	7,581		$	5,616		$	5,186		$	27,883
Cash flow Data:
Cash Provided by Operating Activities	$	2,271		$	1,483		$	12,304		$	9,526		$	5,983
Cash Used by Investing Activities		(5,816	)		(19,589	)		(96,830	)		(19,404	)		(9,612	)
Cash Provided by Financing Activities		4,537			16,748			79,438			9,772			5,457
Balance Sheet data:
Cash and Cash Equivalents	$	1,591					$	600		$	3,188		$	3,217		$	7,700
Other Current Assets		9,346						9,681			6,135			5,256			8,776
Property & Equipment (Net of Accumulated Depreciation, Depletion and Amortization)		127,593						133,016			42,265			24,573			230,240
Other Assets		1,240						1,315			3,703			264			3,335
Total Assets	$	139,771					$	144,611		$	55,291		$	33,311		$	250,050
Current Liabilities, Including Current Portion of Long-term Debt		61,688						53,684			32,297			13,672			11,496
Other Long-term liabilities		12,595						9,513			6,423			1,744			9,681
Long-term Debt, Net of Current Maturities		42,312						45,443			3,360			3,000			—
Total Liabilities	$	116,595					$	108,640		$	42,080		$	18,416		$	21,178
Minority Interests		25,399						36,589			24,130			11,696			—
Owners Equity (Deficit)		(2,223	)					(617	)		(10,920	)		3,198			228,873
Total Liabilities, Minority Interests and Owners' Equity	$	139,771					$	144,611		$	55,291		$	33,311		$	250,050

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Summary Operating and Reserve Data

The following table summarizes our operating and reserve data as of and for each of the periods indicated. The following table includes the non-GAAP financial measure of PV-10. For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flow, its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Selected Historical Financial and Operating Data—Non-GAAP Financial Measures.”

	Year Ended December 31,
	2006			2005			2004
Production
Oil (Bbls)		587,470			378,954			197,461
Natural gas (Mcf)		1,109,494			1,124,743			1,067,402
Oil equivalent (BOE)		772,386			566,416			375,361
Oil and natural gas sales(1)
Oil sales	$	35,789,655		$	20,354,195		$	7,833,066
Natural gas sales		7,806,362			9,163,395			6,325,846
Total	$	43,596,017		$	29,517,590		$	14,158,912
Average sales price(1)
Oil ($ per Bbl)		$  60.92			$  53.71			$  39.67
Natural gas ($ per Mcf)		$    7.04			$    8.15			$    5.93
Oil equivalent ($ per BOE)		$  56.44			$  52.11			$  37.72
Average production cost
Oil equivalent ($ per BOE)		$  19.72			$  20.69			$  17.87
Estimated proved reserves(2)
Oil equivalent (MMBOE)		14.5			9.1			4.1
% Oil		80	%		70	%		49	%
% Proved producing		67	%		74	%		80	%
PV-10 (millions)(3)		$  200.3			$  148.1			$    43.7
Pro forma standardized measure (millions)(4)		$  132.1			$  108.2			$    40.2

(1) The December 31, 2004, 2005 and 2006 information excludes the impact of our financial derivative activities.

(2) The estimates of reserves in the table above conform to the guidelines of the SEC. Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our financial derivative activities. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and present value are based on various assumptions, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

(3) Represents the present value, discounted at 10% per annum (PV-10), of estimated future net revenue before income tax of our estimated proved reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be

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developed and produced based on economic conditions prevailing as of December 31, 2006. The estimated future production is priced at December 31, 2004, 2005 and 2006, without escalation, using $30.35, $57.75 and $57.75 per Bbl of oil, respectively, and $6.48, $10.08 and $5.635 per MMBtu of natural gas, respectively, as adjusted by lease for transportation fees and regional price differentials. The estimated present value of proved reserves does not give effect to indirect expenses such as general and administrative expenses, debt service and future income tax expense, asset retirement obligations or to depletion, depreciation and amortization. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. For an explanation of why we show PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flow, please read “Selected Historical Financial and Operating Data—Non-GAAP Financial Measures.” Please also read “Risk Factors—Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

(4) Because each of the Founding Companies was a flow-through entity for state and federal tax purposes, our historical standardized measure does not deduct state or federal taxes. This differs from our pro forma standardized measure, which deducts state and federal taxes.

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RISK FACTORS

An investment in our common stock involves various risks. You should carefully consider the following risks and all of the other information contained in this prospectus before investing in our common stock. The risks described below are those which we believe are the material risks that we face.

Risks Related to Our Business

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

• changes in global supply and demand for oil and natural gas;

• the actions of certain foreign states;

• the price and quantity of imports of foreign oil and natural gas;

• political conditions, including embargoes, in or affecting other oil producing activities;

• the level of global oil and natural gas exploration and production activity;

• the level of global oil and natural gas inventories;

• production or pricing decisions made by the Organization of Petroleum Exporting Countries (OPEC);

• weather conditions;

• availability of limited refining facilities in the Illinois Basin reducing competition and resulting in lower regional oil prices than other U.S. oil producing regions;

• technological advances affecting energy consumption; and

• the price and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. Our reserve base is heavily weighted towards oil producing properties many of which are utilizing or proposed for secondary recovery methods characterized by higher operating costs than many other types of fields such as those in their primary recovery stage or natural gas fields. The higher operating costs associated with many of our oil fields will make our profitability more sensitive to oil price declines. Lower prices will also negatively impact the value and quantity of our proved and unproved projects. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

PennTex Illinois and Rex Operating are defendants in a putative class action lawsuit concerning complaints of hydrogen sulfide emissions from the Lawrence Field, which could expose us to monetary damages or settlement costs. Rex II, Rex II Alpha, Rex III, Rex IV and PennTex Resources own interests in this field as well.

PennTex Illinois and Rex Operating are defendants in a putative class action lawsuit asserting that the operation of oil wells that are controlled, owned or operated by PennTex Illinois and Rex Operating has resulted

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in contamination of the areas surrounding Bridgeport and Petrolia, Illinois, with hydrogen sulfide, or H₂ S. The complaint asserts several causes of action, including violation of the Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct. PennTex Illinois and Rex Operating have filed a joint answer to the complaint specifically denying virtually all of the allegations in the complaint and asserting affirmative defenses thereto. The plaintiffs have filed a motion for class certification requesting that the court certify the case as a class action. On January 26, 2007, the court issued a scheduling and discovery order stating that the court will schedule a hearing on plaintiffs’ motion for class certification after August 31, 2007. We intend to vigorously oppose the plaintiffs’ motion for certification of the case as a class action.

On January 31, 2007, the plaintiffs filed a motion for leave seeking permission to file an amended complaint that would add a claim against the defendants for alleged violation of the Resource Conservation and Recovery Act, making factual allegations similar to those previously asserted in the plaintiffs’ prior pleadings. A final pretrial conference for this case has been set for August 7, 2008, and the case is scheduled for jury trial on August 18, 2008, in the United States District Court for the Southern District of Illinois located in Benton, Illinois. The parties to this lawsuit have exchanged initial pretrial disclosures as required under the applicable rules and each side has served and responded to pre-deposition written discovery. If, as a result of this lawsuit, we are required to pay significant monetary damages or settlement costs in excess of any insurance proceeds, our financial position and results of operations could be substantially harmed.

Rex IV and PennTex Resources also own non-operated working interests in the same oil wells and related facilities operated by PennTex Illinois that are the subject of this lawsuit. In addition, Rex II, Rex II Alpha and Rex III each own interests in the Illinois Basin. It is possible that the plaintiffs may attempt to join some or all of these entities as parties to the class action lawsuit. In addition, the interests of these other entities might become subject to similar complaints, investigations or lawsuits in the future.

EOR techniques that we may use, such as our Alkali-Surfactant-Polymer flooding in the Lawrence Field, involve more risk than traditional waterflooding.

EOR techniques such as alkali-surfactant-polymer, or ASP, chemical injection involve significant capital investment and an extended period of time, generally a year or longer, from the initial phase of a pilot program until increased production occurs. Our ASP project in the Lawrence Field of the Illinois Basin is in its very early stages and the results of our pilot program could be unsuccessful. In addition, the results of any successful pilot program may not be indicative of actual results achieved in a broader EOR project in the same field or area. Generally, surfactant polymer, including ASP, injection is regarded as involving more risk than traditional waterflood operations. The potential reserves associated with our ASP project in the Lawrence Field are not at this time considered proved. Our ability to achieve commercial production and recognize proved reserves from our EOR projects is greatly contingent upon many inherent uncertainties associated with EOR technology, including ASP technology, geological uncertainties, chemical and equipment availability, rig availability and many other factors.

Absent a sufficient level of vertical fracturing in the New Albany Shale acreage we control, our New Albany Shale project may not be successful.

New Albany Shale reservoirs are complex, often containing unusual features that are not well understood by drillers and producers. The New Albany Shale contains vertical fractures. Results of past drilling in the New Albany Shale have been mixed and are generally believed to be related to whether or not a particular well bore intersects vertical fractures. Certain areas in the New Albany Shale will be more heavily fractured than others. If our area of interest is not subject to the level of vertical fracturing that we expect, our plan for horizontal drilling would not yield our expected results and our business, results of operations or financial condition could be adversely affected.

Our use of horizontal drilling techniques might not be effective in increasing our levels of production in the New Albany Shale.

Because of the unique geological features of the New Albany Shale, successful operations in this area require specialized technical staff expertise in horizontal drilling. Most of the wells in the New Albany Shale

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have been drilled vertically. Where vertical fractures have been encountered, the production has been better. It is expected that horizontal drilling, which is more expensive and complicated than vertical drilling, will allow us to encounter more fractures by drilling perpendicular to the fracture plane. To date, we have only limited experience drilling horizontal wells and this method of drilling may not be as effective (or effective at all) as we currently expect it to be.

A significant part of the value of our production and reserves is concentrated in the Illinois Basin. Because of this concentration, any production problems or changes in assumptions affecting our proved reserve estimates related to these areas could materially adversely impact our business.

For the fourth quarter ended December 31, 2006, 77% of our net daily production came from the Illinois Basin area, and, as of December 31, 2006, approximately 74% of our proved reserves were located in the fields that comprise this area. In addition, for the fourth quarter ended December 31, 2006, approximately 64% of our net daily production came from the Lawrence Field, and, as of December 31, 2006, approximately 54% of our proved reserves were located on this property. If mechanical problems, weather conditions or other events were to curtail a substantial portion of this production, our cash flow could be adversely affected. If ultimate production associated with these properties is less than our estimated reserves, or changes in pricing, cost or recovery assumptions in the area results in a downward revision of any estimated reserves in these properties, our business, financial condition or results of operations could be adversely affected.

We depend on a relatively small number of purchasers for a substantial portion of our revenue. The inability of one or more of our purchasers to meet their obligations or the loss of our market with Countrymark Cooperative, LLP, in particular, may adversely affect our financial results.

We derive a significant amount of our revenue from a relatively small number of purchasers. All of the oil we produce in the Illinois Basin is sold to one refinery, Countrymark Cooperative, LLP. The revenue we received from sales of our oil to Countrymark Cooperative, LLP for the year ended December 31, 2006, constituted approximately 76% of our total oil and gas operating revenue for such period. Our inability to continue to provide services to these key customers, if not offset by additional sales to our customers, could adversely affect our financial condition and results of operations. These companies may not provide the same level of our revenue in the future for a variety of reasons, including their lack of funding, a strategic shift on their part in moving to different geographic areas in which we do not operate or our failure to meet their performance criteria. The loss of all or a significant part of this revenue would adversely affect our financial condition and results of operations.

Our results of operations and cash flow may be adversely affected by risks associated with our oil and gas financial derivative activities, and our oil and gas financial derivative activities may limit potential gains.

We have entered into, and we expect to enter into in the future, oil and gas financial derivative arrangements corresponding to a significant portion of our oil and natural gas production. Many derivative instruments that we employ require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. During the twelve months ended December 31, 2006, we incurred realized losses of $4,436,347 from our financial derivatives, which effectively reduces our total revenues from our oil and gas sales. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Oil and Gas Activities.”

If our actual production and sales for any period are less than the corresponding volume of derivative contracts for that period (including reductions in production due to operational delays) or if we are unable to perform our activities as planned, we might be forced to satisfy all or a portion of our derivative obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. In addition, our oil and gas financial derivative activities can result in substantial losses. Such losses could occur under various circumstances, including any circumstance in which a

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counterparty does not perform its obligations under the applicable derivative arrangement, the arrangement is imperfect or our derivative policies and procedures are not followed or do not work as planned. Under the terms of our anticipated senior credit facility with KeyBank National Association, the percentage of our total production volumes with respect to which we will be allowed to enter into derivative contracts will be limited, and we therefore retain the risk of a price decrease for our remaining production volume.

New Albany Shale wells produce a significant amount of water which requires disposal into permeable reservoirs that we may be unable to find at a reasonable cost.

Gas and water are produced together from the New Albany Shale. Water is often produced in significant quantities, especially early in the producing life of a well. We plan to dispose of this produced water by means of injecting it into other porous and permeable formations via disposal wells located adjacent to producing wells. If we are unable to find such porous and permeable reservoirs into which to inject this produced water or if we are prohibited from injecting because of governmental regulation, then our cost to dispose of produced water could increase significantly, thereby affecting the economic viability of producing the New Albany Shale wells.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.

There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. We account for our natural gas and crude oil exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future net revenues, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but it will reduce our earnings and stockholders’ equity.

A write down could occur if oil and gas prices decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results. Because our properties currently serve, and will likely continue to serve, as collateral for advances under our anticipated and future credit facilities, a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. It is likely that the cumulative effect of a write-down could also negatively impact the value of our securities, including our common stock.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

We review our oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not

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reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the recorded book values associated with oil and gas properties.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “—Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves” for a discussion of the uncertainties involved in these processes. Our costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:

• delays imposed by or resulting from compliance with regulatory requirements;

• pressure or irregularities in geological formations;

• shortages of or delays in obtaining equipment and qualified personnel;

• equipment failures or accidents;

• adverse weather conditions;

• reductions in oil and natural gas prices;

• oil and natural gas property title problems; and

• market limitations for oil and natural gas.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

Estimates of oil and natural gas reserves are inherently imprecise. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves. To prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

• actual prices we receive for oil and natural gas;

• actual cost of development and production expenditures;

• the amount and timing of actual production;

• supply of and demand for oil and natural gas; and

• changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our prospects are in various stages of evaluation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies, and the study of producing fields in the same area, will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercially viable quantities. Moreover, the analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects.

We cannot control activities on properties that we do not operate and are unable to control their proper operation and profitability.

We do not operate all of the properties in which we own an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:

• nature and timing of drilling and operational activities;

• timing and amount of capital expenditures;

• expertise and financial resources;

• the approval of other participants in drilling wells; and

• selection of suitable technology.

If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil

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and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas may have several adverse affects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending on reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, results of operations and financial condition.

Our future acquisitions may yield revenues or production that vary significantly from our projections.

In acquiring producing properties, we will assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to the properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations.

Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for, and development, production and acquisition of, oil and natural gas reserves. To date, we have financed capital expenditures primarily with proceeds from bank borrowings and cash generated by operations. We intend to finance our capital expenditures with the sale of equity, asset sales, cash flow from operations and current and new financing arrangements. Our cash flow from operations and access to capital are subject to a number of variables, including:

• our proved reserves;

• the level of oil and natural gas we are able to produce from existing wells;

• the prices at which oil and natural gas are sold; and

• our ability to acquire, locate and produce new reserves.

If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may need to seek additional financing in the future. In addition, we may not be

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able to obtain debt or equity financing on terms favorable to us, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

With the increase in the prices of oil and natural gas during the past few years, we have encountered an increase in the cost of securing drilling rigs, equipment and supplies. Shortages or the high cost of drilling rigs, equipment, supplies and personnel are expected to continue in the near-term. In addition, larger producers may be more likely to secure access to such equipment by offering more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, our ability to convert our reserves into cash flow could be delayed and the cost of producing those reserves could increase significantly, which would materially and adversely affect our results of operation and financial condition.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations, and we may not have enough insurance to cover all of the risks that we face.

We maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our results of operations, financial condition and cash flows.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

• environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

• abnormally pressured formations;

• mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses;

• fires and explosions;

• personal injuries and death; and

• natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us. If a significant accident or other event occurs and is not fully covered by insurance, then that accident or other event could adversely affect our results of operations, financial condition and cash flows.

Our business may suffer if we lose key personnel.

Our operations depend on the continuing efforts of our executive officers and the senior management of Rex Operating. Our business or prospects could be adversely affected if any of these persons does not continue in his management role with us and we are unable to attract and retain qualified replacements. Additionally, we do not carry key person insurance for any of our executive officers or senior management.

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We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

The exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, and local laws and regulations. We may incur substantial expenditures in order to comply with these laws and regulations, which may require:

• discharge permits for drilling operations;

• drilling bonds;

• reports concerning operations;

• the spacing of wells;

• unitization and pooling of properties; and

• the payment of taxes.

Under these laws, we could be subject to claims for personal injury or property damages, including natural resource damages, which may result from the impacts of our operations. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs of compliance. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition and results of operations.

Our operations expose us to substantial costs and liabilities with respect to environmental matters.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations governing the release of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with our drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution that may result from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory or remedial obligations or injunctive relief. Under existing environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the release resulted from our operations, or our operations were in compliance with all applicable laws at the time they were performed. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. We may not be able to compete successfully in the future in acquiring prospective

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reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

Risks Related to Our Common Stock and This Offering

The market price for our shares of common stock may be volatile and could be subject to fluctuations.

The market price of our common stock may be influenced by many factors, some of which are beyond our control, including:

• changes in oil and natural gas prices;

• changes in the oil and natural gas industries and the overall economic environment;

• our quarterly or annual earnings, or those of other companies in our industry;

• the failure of securities analysts to cover our common stock after this offering or changes in financial estimates by analysts;

• changes in market valuations of similar companies;

• announcements by us or our competitors of significant contracts or acquisitions;

• the loss of a significant customer;

• additions or departures of key management personnel;

• future sales by us or other holders of our common stock; and

• other factors described in these “Risk Factors.”

In addition, the stock market from time to time experiences extreme volatility that has often been unrelated to the performance of particular companies. These market fluctuations may cause our stock price to fall regardless of our performance.

You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock.

We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present stockholders and purchasers of common stock offered hereby. Following the closing of this offering, we will be authorized to issue 100,000,000 shares of common stock and 100,000 shares of preferred stock with such designations, preferences and rights as may be determined by our board of directors. Immediately prior to the closing of this offering, we will have 21,994,702 shares of common stock outstanding. Pursuant to our new long-term incentive plan, we will also reserve an amount equal to 10% of the number of shares of our common stock outstanding immediately after completion of this offering for future issuance as restricted stock, stock options, phantom stock, stock appreciation rights or other equity-based grants to employees and directors. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes or for other business purposes. Future sales of substantial amounts of our common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.

We may require additional capital to expand our business, and this capital might not be available on acceptable terms, or at all.

We intend to continue to make investments to expand our business and may require additional funds to respond to business opportunities and challenges. Accordingly, we may need equity or debt financings to secure

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additional funds. If we raise additional funds through issuances of equity or convertible debt securities, our stockholders could suffer significant dilution, and any new equity securities we issue could have rights, preferences and privileges superior to those of holders of our common stock. Any debt financing obtained by us in the future could involve restrictive covenants relating to our capital raising activities and other financial and operational matters, which may make it more difficult for us to obtain additional capital and to pursue business opportunities, including potential acquisitions. In addition, we may be unable to obtain additional financing on terms favorable to us, if at all. If we are unable to obtain adequate financing or financing on terms satisfactory to us when we require it, our ability to continue to support our business growth and to respond to business challenges could be significantly limited.

Our internal control over financial reporting may be insufficient to allow us to accurately and timely report our financial results, which could adversely affect the trading price of our common stock.

Effective internal controls are necessary for us to provide timely and reliable financial reports to operate successfully as a public company. Our independent registered public accounting firm, Malin, Bergquist & Company, LLP, issued a letter to our management and audit committee in April 2007 that identified material weaknesses in internal control over financial reporting with respect to the audits of 3 of the Founding Companies. Malin, Bergquist has advised us that these matters would not be material weaknesses on the combined entity but that they would consider such matters to constitute significant deficiencies in our internal control over financial reporting. A significant deficiency is a control deficiency, or combination of deficiencies, that adversely affects a company’s ability to initiate, authorize, record, process or report external financial data reliably in accordance with GAAP such that there is a more than remote likelihood that a misstatement of the entity’s annual or interim financial statements that is more than inconsequential will not be prevented or detected. Management has taken a number of remedial measures to address several of the issues raised by Malin, Bergquist. If these measures, together with other remedial measures that management is in the process of implementing, are insufficient to address the issues raised, or if material weaknesses or additional significant deficiencies in our internal control over financial reporting are discovered in the future, we may fail to meet our financial reporting obligations. If we fail to meet these obligations, it could affect our ability to issue accurate and timely financial statements, which could adversely affect the trading price of our common stock.

We have no operating history and the Founding Companies have a limited operating history, and our business may not be as successful as we envision.

We were incorporated in March 2007 and have not conducted any operations other than in connection with the proposed Reorganization Transactions. We therefore have no operating history and some of the Founding Companies have a limited operating history from which you can evaluate our business and prospects. Moreover, several of the Founding Companies have incurred operating losses and have yet to recognize operating income. Our prospects must be considered in light of the risks and uncertainties encountered by an oil and gas company in the current market environment. If we cannot successfully address these risks, our business, future results of operations and financial condition may be materially adversely affected, and we may continue to incur operating losses associated with the businesses of certain of the Founding Companies in the future.

There has been no active trading market for our common stock, and an active trading market may not develop.

Prior to this offering, there has been no public market for our common stock. We have applied to list our common stock on The NASDAQ Global Market. We do not know if an active trading market will develop for our common stock or how our common stock will trade in the future, which may make it more difficult for you to sell your shares. Negotiations among the underwriters, the selling stockholders and us will determine the initial public offering price. You may not be able to resell your shares at or above the initial public offering price.

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Because we have no plans to pay dividends on our common stock, stockholders must look solely to appreciation of our common stock in order to realize a gain on their investments.

We do not anticipate paying any dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, the expected terms of our new senior credit facility may limit payment of dividends without the prior written consent of the lenders. Accordingly, if you purchase shares in this offering, the price of our common stock must appreciate in order to realize a gain on your investment. This appreciation may not occur.

Our certificate of incorporation, bylaws and Delaware law contain provisions that could make it more difficult for a third party to acquire us without the consent of our board of directors and our Chairman and other executive officers, which collectively are expected to beneficially own approximately 45.7% of the outstanding shares of our common stock after giving effect to the Reorganization Transactions and this offering.

Our board of directors has the right to issue preferred stock without stockholder approval, which could be used to dilute the stock ownership of a potential hostile acquirer. Delaware law also imposes certain restrictions on mergers and other business combinations between any holder of 15% or more of our outstanding voting stock. These provisions apply even if the offer may be considered beneficial by some stockholders. In addition, Mr. Shaner, our Chairman, is expected to beneficially own approximately 31.5%, and our other executive officers are expected to collectively own approximately 14.2%, of the outstanding shares of our common stock after giving effect to the Reorganization Transactions and this offering.

Please read “Description of Capital Stock—Anti-Takeover Effects of Delaware Law and Our Certificate of Incorporation and Bylaws” for more information about these provisions.

We are parties to several agreements with companies owned and controlled by our chairman, Lance T. Shaner. Mr. Shaner’s ownership and association with these companies could create a possible conflict of interest between the interests of those companies and Mr. Shaner’s duties and obligations to us.

Pursuant to a written agreement, we currently lease the office building that serves as our headquarters from Shaner Brothers, LLC, a Pennsylvania limited liability company which is owned and controlled by our Chairman, Lance T. Shaner. The lease agreement provides for an initial term of three years and expires on August 9, 2009. We currently pay rent to Shaner Brothers in the amount of $7,908 per month. We obtain certain administrative services, such as information technology, payroll, benefits administration and tax preparation and consulting services, from Shaner Hotel Group Limited Partnership, a Delaware limited partnership owned and controlled by Mr. Shaner. Pursuant to the terms of the three written agreements, we pay Shaner Hotels set hourly fees for the administrative services provided, plus reimbursement for its reasonable out-of-pocket expenses. Each of the three agreements may be terminated by either party upon ninety days advance written notice. We also currently have an oral month-to-month agreement with Charlie Brown Air Corp, a New York corporation owned and controlled by Mr. Shaner, regarding the use of two airplanes owned by Charlie Brown. Under our oral agreement, we have agreed to pay a monthly fee for the right to use the airplane equal to our percentage (based upon the total number of hours of use of the airplanes by us) of the monthly fixed costs for the airplanes, plus a variable per hour flight rate of $1,350 per hour.

Each of these agreements were entered into by us and each company controlled by Mr. Shaner prior to the consummation of the Reorganization Transactions and at a time when Mr. Shaner controlled each of the Founding Companies. All of the above agreements were negotiated between related parties, and, therefore, the terms, including fees payable, may not be as favorable to us as if they had been negotiated with an unaffiliated third party. Following the consummation of the Reorganization Transactions and this offering, Mr. Shaner will

30

continue to serve as our Chairman and will be a significant stockholder of the Company. Mr. Shaner’s continued ownership and association with the Shaner companies described above could create a possible conflict of interest between the interests of those companies and Mr. Shaner’s duties and obligations to us.

Please read “Related Party Transactions, Conflicts of Interest and Certain Relationships” for more information about these potential conflicts of interests.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. All statements other than statements of historical facts included in this prospectus, including but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs, savings and plans and objectives of management for future operations, are forward-looking statements. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe” or “continue” or the negative thereof or variations thereon or similar terminology.

These forward-looking statements are subject to numerous assumptions, risks and uncertainties. Factors which may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by us in those statements include, among others, the following:

• the quality of our properties with regard to, among other things, the existence of reserves in economic quantities;

• uncertainties about the estimates of reserves;

• our ability to increase our production and oil and natural gas income through exploration and development;

• our ability to successfully apply horizontal drilling techniques and tertiary recovery methods;

• the number of well locations to be drilled and the time frame within which they will be drilled;

• the timing and extent of changes in commodity prices for crude oil and natural gas;

• domestic demand for oil and natural gas;

• drilling and operating risks;

• the availability of equipment, such as drilling rigs and transportation pipelines;

• changes in our drilling plans and related budgets;

• the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity; and

• other factors discussed under “Risk Factors.”

Because such statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. You are cautioned not to place undue reliance on such statements, which speak only as of the date of this prospectus. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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USE OF PROCEEDS

We expect to receive net proceeds from the sale of shares offered by us of approximately $101.9 million, based on an assumed offering price of $12.00 per share after deducting estimated offering expenses of $1.3 million remaining unpaid as of May 31, 2007, and underwriting discounts and commissions of $7.2 million. If the underwriters exercise their over-allotment option in full, we estimate that the net proceeds to us will increase by approximately $24.7 million after deducting estimated offering expenses and underwriting discounts and commissions. Our total offering expenses, approximately $1 million of which has already been paid by the Founding Companies, are estimated to be $2.3 million excluding underwriting discounts and commissions. We intend to use any net proceeds from the exercise of the over-allotment option to fund an additional portion of our expected 2007 capital expenditures and for other general corporate purposes.

We intend to use our net proceeds from this offering to retire all of the senior debt facilities and other notes payable to unrelated parties of the Founding Companies, which we expect to be approximately $101.1 million at the completion of this offering, and the remainder, expected to be approximately $800,000 (or $25.5 million if the underwriters exercise their over-allotment option in full), to fund a portion of our 2007 expected capital expenditures, and general corporate purposes, including for working capital.

Each dollar increase or decrease in the per share offering price will increase or decrease the amount of net proceeds we receive from this offering by $8.6 million. A $1.00 decrease in the assumed offering price would cause us to retain approximately $7.8 million of indebtedness under our existing senior debt facilities (assuming no exercise of the underwriters’ over-allotment option).

The senior debt facilities of the Founding Companies have historically been utilized to fund a portion of our acquisitions and for working capital purposes including exploration and development activities. As of December 31, 2006, the Founding Companies had combined senior debt facilities of $84.9 million, with a weighted average interest rate of 8.76% per annum. The senior debt facilities mature 47% in 2007, 9% in 2008, 43% in 2009 and 1% thereafter. During the year ended December 31, 2006, we utilized approximately $23 million in debt to fund the Team Energy acquisition, and $35 million in debt to fund the TSAR Energy acquisition.

Certain affiliates of the underwriters in this offering are lenders under the Founding Companies’ credit facilities and will receive a portion of the net proceeds we receive from this offering based on the amount of the loans they have extended under these credit facilities.

We will not receive any proceeds from the sale of shares of our common stock by the Selling Stockholders.

DIVIDEND POLICY

We do not anticipate paying any dividends on the shares of our common stock in the foreseeable future. We currently intend to reinvest our earnings in our capital projects and acquisitions. In addition, the expected terms of our anticipated new senior credit facility may limit our ability to pay dividends in certain circumstances.

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CAPITALIZATION

The following table sets forth at March 31, 2007:

• on an actual basis, the combined cash and cash equivalents and the combined capitalization of the Founding Companies; and

• on a pro forma as adjusted basis to reflect:

• the consummation of the Reorganization Transactions; and

• the sale of 9,200,000 shares of common stock in this offering at an assumed initial public offering price of $12.00 per share, after deducting $7.2 million for the estimated underwriting discounts and commissions and $1.7 million for the estimated offering expenses remaining unpaid and the application of the estimated net proceeds from this offering as set forth under “Use of Proceeds.”

A (i) $1.00 increase in the assumed public offering price of $12.00 per share would increase each of cash and cash equivalents, additional paid-in capital, total owners’ equity and total capitalization by $8.6 million, and (ii) $1.00 decrease in the assumed offering price of $12.00 per share would decrease additional paid-in capital, total owners’ equity and total capitalization by $8.6 million, would cause total debt to be $2.5 million and would cause no change in cash and cash equivalents, in each case, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated expenses and underwriting discounts and commissions payable by us.

You should read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements, pro forma financial statements and the accompanying notes included elsewhere in this prospectus.

	As of March 31, 2007
	Combined Founding Companies Actual			Pro forma As Adjusted
	(Unaudited)			(Unaudited)
	(In thousands)
Cash and cash equivalents(1)	$	1,591		$	7,700
Total debt (including current maturities)(2)		95,417			—
Owners’ Equity:
Common stock, $.001 par value; 100,000,000 authorized; 10 issued and outstanding actual; 31,194,702 issued and outstanding as adjusted		1			31
Preferred stock, $.001 par value; 100,000 authorized; none issued and outstanding		—			—
Additional paid-in capital		1,460			228,841
Accumulated other comprehensive income		—			—
Accumulated deficit		(420	)		—
Partners’ and Members’ Deficit		(3,264	)		—
Total Owners’ Equity (Deficit)	$	(2,223	)	$	228,873
Minority interests equity	$	25,399			—

(1) Reflects the change in cash from the offering assuming $1.7 million in offering expenses as of March 31, 2007. As of May 31, 2007, we estimate the offering expenses remaining unpaid were $1.3 million, which would result in an increase in pro forma cash of approximately $400,000.

(2) We expect that total debt will be approximately $101.1 million at the completion of this offering. We estimate that this will decrease the cash and cash equivalents shown in the table above by approximately $5.7 million. If our assumed offering price of $12.00 per share decreases by $1.00, we would have $7.8 million of remaining total debt and our cash and cash equivalents would not change.

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DILUTION

Our pro forma net tangible book value, before the initial public offering but after the issuance of shares for minority interests, at March 31, 2007 is approximately $127.9 million, or $5.82 per share of our common stock. Net tangible book value per share represents our total tangible assets reduced by our total liabilities and divided by the number of shares of common stock outstanding. Dilution in net tangible book value per share represents the difference between the amount per share that you pay in this offering and the net tangible book value per share immediately after this offering.

After giving effect to the receipt of the estimated net proceeds from the sale by us of 9,200,000 shares, assuming an initial public offering price of $12.00 per share, and the application of the estimated net proceeds therefrom as described under “Use of Proceeds,” our net tangible book value at March 31, 2007, would have been approximately $228.8 million, or $7.34 per share of common stock. This represents an immediate increase in net tangible book value per share of $1.52 to existing stockholders and an immediate decrease in net tangible book value per share of $4.66 to you. The following table illustrates the dilution.

Assumed public offering price per share	$	12.00
Net tangible book value per share before the offering	$	5.82
Increase per share attributable to this offering	$	1.52
Net tangible book value per share after this offering	$	7.34
Dilution per share to new investors in this offering	$	4.66

A $1.00 increase (decrease) in the assumed initial public offering price of $12.00 per share would increase (decrease) our net tangible book value per share after this offering by $0.62 per share and the dilution per share to new investors in this offering by $0.38 per share, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table sets forth, as of March 31, 2007, the differences between the amounts paid or to be paid by the groups set forth in the table with respect to the aggregate number of shares of our common stock acquired or to be acquired by each group.

	Shares Purchased(1)			Total Consideration				Average Price Per Share
	Number	Percent		Amount		Percent
Existing stockholders(2)	21,994,702	70.5	%	$	145,688,136	56.9	%	$	6.62
New investors in this offering(3)	9,200,000	29.5	%		110,400,000	43.1	%	$	12.00
Total	31,194,702	100.0	%	$	256,088,136	100.0	%	$	8.21

(1) The number of shares disclosed for the existing stockholders includes shares being sold by the selling stockholders in this offering. The number of shares disclosed for the new investors does not include the shares being purchased by the new investors from the selling stockholders in this offering.

(2) Includes Lance T. Shaner and the other equity investors in the Founding Companies. Mr. Shaner’s consideration paid is based upon his total consideration or equity contributions paid to the Founding Companies. Other investors’ consideration paid is based upon the value of the shares received for their minority interests in the Founding Companies based upon the initial public offering price.

(3) Before underwriters’ commissions and our expenses.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

Summary Financial Data

The following table shows selected combined financial data of the Founding Companies as of and for each of the periods indicated. The combined financial statements of the Founding Companies present historical combined financial data as of and for the years ended December 31, 2006, 2005, 2004, 2003 and 2002 as of March 31, 2007 and for the three months ended March 31, 2007 and 2006. The historical combined financial statements as of and for the years ended December 31, 2006, 2005 and 2004 are derived from the historical audited financial data of the Founding Companies. The historical combined financial statements as of and for the years ended December 31, 2002 and 2003 are derived from the historical unaudited financial data of the Founding Companies. The historical combined financial statements as of March 31, 2007 and for the three months ended March 31, 2007 and 2006 are derived from the historical unaudited financial data of the Founding Companies. All of the Founding Companies all of which are under the common control of Lance T. Shaner, our Chairman, through his direct and indirect ownership interests and other contractual arrangements, as well as under the common management of Rex Operating. All material intercompany balances and transactions have been eliminated. As each of the Founding Companies was taxed as a partnership for each of the periods indicated for federal and state income tax purposes, the following statements make no provision for income taxes. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated historical financial statements and related notes included elsewhere in this prospectus. These selected combined historical financial results may not be indicative of our future financial or operating results.

The following table includes the non-GAAP financial measure of EBITDAX. For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “—Non-GAAP Financial Measures.”

	Three Months Ended March 31,						Year Ended December 31,
	2007			2006			2006			2005			2004			2003			2002
	(unaudited)			(unaudited)												(unaudited)			(unaudited)
Statement of operations data:
Operating Revenues:
Oil and Gas Sales	$	12,774,851		$	9,168,791		$	43,596,017		$	29,517,590		$	14,158,912		$	5,192,538		$	390,054
Realized Gain (Loss) from Derivatives		264,838			(1,389,857	)		(4,436,347	)		(7,929,478	)		(941,511	)		—			—
Unrealized Gain (Loss) from Derivatives		(3,436,845	)		119,539			5,043,220			(5,541,043	)		(1,395,531	)		—			—
Other Operating Revenues		100,221			127,143			469,582			270,140			697,412			927,977			—
Total Operating Revenue		9,703,065			8,025,616			44,672,472			16,317,209			12,519,282			6,120,515			390,054
Operating Expenses:
Production and Lease Operating		6,105,097			2,443,839			15,234,055			11,720,979			6,707,774			2,203,611			178,105
General and Administrative		1,981,995			843,707			6,212,139			3,788,932			2,228,986			1,177,444			38,689
Depletion, Depreciation and Amortization		4,073,259			2,065,131			11,222,306			3,320,000			2,039,265			1,015,296			130,435
Asset Impairment		585,042			—			—			107,119			3,024,267			—			—
Total Operating Expenses		12,745,393			5,352,677			32,668,500			18,937,030			14,000,292			4,396,351			347,229
Income (Loss) from Operations		(3,042,328	)		2,672,939			12,003,972			(2,619,821	)		(1,481,010	)		1,724,164			42,825
Other Income (Expenses):
Interest Income		8,917			35,968			93,684			444,438			18,631			42,446			10
Interest Expense		(2,084,820	)		(766,329	)		(6,110,023	)		(1,697,461	)		(867,386	)		(171,324	)		(345	)
Gain on Sale or Disposal of Oil and Gas Properties		176,482			—			91,416			1,016,545			659,364			—			—
Other Income (Expense)		(43,506	)		(113,097	)		(131,713	)		215,678			(21,171	)		—			—
Total Other Income (Expense)		(1,942,927	)		(843,458	)		(6,056,636	)		(20,800	)		(210,562	)		(128,878	)		(335	)
Net Income Before Minority Interests		(4,985,255	)		1,829,481			5,947,336			(2,640,621	)		(1,691,572	)		1,595,286			42,490
Minority Interests Share of Income (Loss)		(2,727,892	)		921,064			2,133,655			2,303,982			(2,061,623	)		(967,640	)		(16,996	)
Net Income	$	(2,257,363	)	$	908,417		$	3,813,681		$	(4,944,603	)	$	370,051		$	627,646		$	25,494

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	Three Months Ended March 31,						Year Ended December 31,
	2007			2006			2006			2005			2004			2003			2002
	(unaudited)			(unaudited)												(unaudited)			(unaudited)
Other financial data:
EBITDAX (Before Minority Interests)	$	5,185,794		$	4,505,434		$	18,142,761		$	7,580,564		$	5,616,246		$	2,739,460		$	173,260
Cash flow data:
Cash provided by operating activities		2,270,736			1,483,404			12,303,864			9,526,277			5,983,247			630,738			150,044
Cash used by investing activities		(5,815,970	)		(19,589,193	)		(96,829,974	)		(19,404,136	)		(9,611,682	)		(6,089,633	)		(44,140	)
Cash provided by financing activities		4,536,701			16,748,187			79,438,356			9,771,951			5,457,300			5,912,952			(94,978	)
Balance sheet data:
Cash and Cash Equivalents		1,591,263						599,796			3,187,550			3,217,217			1,347,184			38,881
Other Current Assets		9,345,909						9,681,050			6,135,104			5,255,662			1,574,993			20,286
Property & Equipment (Net of Accumulated Depreciation)		127,593,494						133,015,856			42,264,856			24,573,484			15,826,036			432,213
Other Assets		1,239,996						1,314,650			3,703,104			264,480			758,856			20,103
Total Assets		139,770,662						144,611,352			55,290,614			33,310,843			19,507,069			511,483
Current Liabilities, Including Current Portion of Long-term Debt		61,688,138						53,683,916			32,297,234			13,672,246			2,864,404			38,184
Other long-term Liabilities		12,595,082						9,512,796			6,423,103			1,744,084			487,150			—
Long-term Debt, Net of Current Maturities		42,311,563						45,442,644			3,360,047			3,000,000			4,258,955			175,000
Total Liabilities		116,594,783						108,639,356			42,080,384			18,416,330			7,610,509			213,184
Minority Interests		25,399,110						36,589,360			24,129,968			11,696,234			9,560,750			119,320
Owners’ Equity		(2,223,231	)					(617,364	)		(10,919,738	)		3,198,279			2,335,810			178,979
Total Liabilities, Minority Interests and Owners’ Equity	$	139,770,662					$	144,611,352		$	55,290,614		$	33,310,843		$	19,507,069		$	511,483

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Summary Operating and Reserve Data

The following table summarizes our operating and reserve data as of and for each of the periods indicated. The following table includes the non-GAAP financial measure of PV-10. For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flow, its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “—Non-GAAP Financial Measures.”

	Year Ended December 31,
	2006			2005			2004
Production
Oil (Bbls)		587,470			378,954			197,461
Natural gas (Mcf)		1,109,494			1,124,743			1,067,402
Oil equivalent (BOE)		772,386			566,416			375,361
Oil and natural gas sales(1)
Oil sales	$	35,789,655		$	20,354,195		$	7,833,066
Natural gas sales		7,806,362			9,163,395			6,325,846
Total	$	43,596,017		$	29,517,590		$	14,158,912
Average sales price(1)
Oil ($ per Bbl)	$	60.92		$	53.71		$	39.67
Natural gas ($ per Mcf)	$	7.04		$	8.15		$	5.93
Oil equivalent ($ per BOE)	$	56.44		$	52.11		$	37.72
Average production cost
Oil equivalent ($ per BOE)	$	19.72		$	20.69		$	17.87
Estimated proved reserves(2)
Oil equivalent (MMBOE)		14.5			9.1			4.1
% Oil		80	%		70	%		49	%
% Proved producing		67	%		74	%		80	%
PV-10 (millions)	$	200.3		$	148.1		$	43.7
Pro forma standardized measure (millions)(3)		132.1		$	108.2		$	40.2

(1) The December 31, 2004, 2005 and 2006 information excludes the impact of our financial derivative activities.

(2) The estimates of reserves in the table above conform to the guidelines of the SEC. Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our financial derivative activities. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The estimated present value of proved reserves does not give effect to indirect expenses such as general and administrative expenses, debt service and future income tax expense, asset retirement obligations or to depletion, depreciation and amortization. The reserve information shown is estimated. The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and present value are based on various assumptions, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

(3) Because each of the Founding Companies was a flow-through entity for state and federal tax purposes, our historical standardized measure does not deduct state or federal taxes. This differs from our pro forma standardized measure, which deducts state and federal taxes.

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Non-GAAP Financial Measures

We include in this prospectus our calculations of EBITDAX and PV-10, which are non-GAAP financial measures. Below, we provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measure as calculated and presented in accordance with GAAP.

EBITDAX

“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized losses from financial derivatives, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX as defined above is used as a financial measure by our management team and by other users of our financial statements such as our commercial bank lenders.

• Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial or capital structure;

• The financial performance of our assets and valuation of the entity without regard to financing methods, capital structure or historical cost basis;

• Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and

• The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) in measuring our performance or used as an exclusive measure of cash flow because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions and other sources and uses of cash, which are disclosed in our statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders and under our proposed senior credit facility, and we believe this is a measure commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed our EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.

We believe EBITDAX assists our lenders and investors in comparing a company’s performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Additionally, we are required to pay federal and state taxes which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.

To compensate for these limitations, we believe that it is important to consider both net income determined under GAAP and EBITDAX to evaluate our performance.

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The following table presents a reconciliation of our net income to our EBITDAX on a historical basis for each of the periods indicated.

	Three Months Ended March 31,					Year Ended December 31,
	2007			2006		2006		2005			2004			2003		2002
Net Income (Loss) Before Minority Interests	$	(4,985,255	)	$	1,829,481	$	5,947,336	$	(2,640,621	)	$	(1,691,572	)	$	1,595,286	$	42,490
Add Back Depletion, Depreciation & Amortization		4,073,259			2,065,131		11,222,306		3,320,000			2,039,265			1,015,296		130,435
Add Back Interest Expense		2,084,820			766,329		6,110,023		1,697,461			867,386			171,324		345
Add Back Exploration & Impairment Expenses		585,042			—		—		107,119			3,024,267			—		—
Less Interest Income		8,917			35,968		93,684		444,438			18,631			42,446		10
Less Unrealized Gains (Losses) from Financial Derivatives		(3,436,845	)		119,539		5,043,220		(5,541,043	)		(1,395,531	)		—		—
EBITDAX Before Minority Interests	$	5,185,794		$	4,505,434	$	18,142,761	$	7,580,564		$	5,616,246		$	2,739,460	$	173,260

PV-10

The following table shows our reconciliation of our PV-10 to our pro forma standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with GAAP). PV-10 represents our estimate of the present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proved reserves. Our estimated future net revenues as of December 31, 2004, 2005 and 2006 were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on economic conditions prevailing on that date. The estimated future production is priced at December 31, 2004, 2005 and 2006, without escalation, using $30.35, $57.75 and $57.75 per Bbl of oil, respectively, and $6.48, $10.08 and $5.635 per MMBtu of natural gas, respectively, as adjusted by lease for transportation fees and regional price differentials. Management believes that PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

	2006		2005		2004
Reconciliation of PV-10 to Pro forma standardized measure (millions)
Pro forma standardized measure of discounted future net cash flows	$	132.1	$	108.2	$	40.2
Add: Present value of future income tax discounted at 10%		62.9		37.5		1.7
Add: Present value of future asset retirement obligations discounted at 10%		5.3		2.4		1.8
PV-10	$	200.3	$	148.1	$	43.7

39

PRO FORMA COMBINED FINANCIAL DATA

Pro Forma Combined Financial Statements

The pro forma financial statements as of and for the year ended December 31, 2006 are derived from the audited combined financial statements of our predecessor, the Founding Companies of Rex Energy Corporation, and the audited statements of revenue and direct operating expenses of three acquisitions completed during the year ended December 31, 2006 included elsewhere in this prospectus. The pro forma financial statements as of and for the three months ending March 31, 2007 are derived from the unaudited financial statements of the Founding Companies of Rex Energy Corporation for the period indicated. The pro forma adjustments to the statement of operations for the year ended December 31, 2006 have been prepared as if certain transactions had taken place on January 1, 2006. The pro forma adjustments for the three months ended March 31, 2007 have been prepared as if certain transactions had taken place on March 31, 2007, in the case of the pro forma balance sheet, and on January 1, 2007 in the case of the pro forma statements of operations. These transactions include:

• the Reorganization Transactions including the contemplated acquisitions of minority interests, exchanges of interests and the mergers of the Founding Companies under the parent holding company as a taxable corporation;

• the initial public offering of our common stock at an assumed initial public offering price of $12.00 per share and assuming the underwriters’ over-allotment option is not exercised and the application of the proceeds as described in “Use of Proceeds”, including the repayment of all outstanding senior credit facilities and certain other related debts and corresponding increase in cash; and

• the consummation of the following three acquisitions, each of which occurred in 2006:

• our acquisition in June 2006 of interests in approximately 177 producing oil wells and related infrastructure in Posey and Gibson Counties, Indiana and Lawrence County, Illinois for approximately $22.7 million from Team Energy, L.L.C.;

• our acquisition in June 2006 of certain non-operating interests associated with the Team Energy leases for $1.2 million; and

• our acquisition in October 2006 of interests in the Lawrence, West Kenner and St. James fields in Illinois and the El Nora field in Indiana for approximately $35.2 million from TSAR Energy II, L.L.C.

These adjustments are based on currently available information and certain estimates and assumptions, and, therefore, the actual effects of the transactions described above may differ from the effects reflected in the pro forma financial statements. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of those transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions.

The accompanying statement of revenues and direct operating expenses for the Team Energy acquisition were derived from the historical accounting records of the sellers. The accompanying statements of revenues and direct operating expenses for the TSAR Energy II acquisitions were derived from the historical accounting records of the Founding Companies as if we were the operator of these properties prior to the acquisition of the additional interest. Although the statements of revenues and direct operating expenses for the Team Energy and TSAR Energy II acquisitions do not include depreciation, depletion and amortization, income taxes or interest expense, these costs have been included on a pro forma basis. No pro forma general and administrative expenses were incurred as a result of either the Team Energy or the TSAR Energy II acquisitions, as the Team Energy properties were located in close proximity to our other assets in the Illinois Basin, and we were the operator of the TSAR Energy II properties prior to the acquisition.

Each of the Founding Companies was taxed as a partnership for the year ended December 31, 2006 for federal and state income tax purposes. We have included a provision for state and federal income taxes on a pro

40

forma basis as if we had been taxed as a corporation for the year ended December 31, 2006. We have not attempted to show pro forma increased general and administrative costs which we may have incurred had we been a public company during the year ended December 31, 2006.

You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our audited historical combined financial statements, the audited historical financial statements of each of the Founding Companies and our unaudited pro forma financial statements and related notes included elsewhere in this prospectus. This pro forma combined historical financial statement has not been audited and may not be indicative of our future financial or operating results.

41

REX ENERGY CORPORATION

UNAUDITED PRO FORMA COMBINED CONDENSED BALANCE SHEET

	March 31, 2007
	Founding Companies Combined			Pro Forma Adjustments for the Offering			Pro Forma as Adjusted
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,591,263		$	6,108,266	(a)	$	7,699,529
Accounts Receivable		7,059,706			(569,680	)(a)		6,490,027
Short-Term Derivative Instruments		132,092						132,092
Inventory, Prepaid Expenses and Other		2,154,110						2,154,110
Total Current Assets		10,937,171						16,475,758
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		131,086,091			74,366,236	(b)		205,452,327
Unevaluated Oil and Gas Properties		9,934,237			28,280,118	(b)		38,214,355
Other Property and Equipment		4,122,537						4,122,537
Wells in Progress		1,865,586						1,865,586
Pipelines		1,802,147						1,802,147
Total Property and Equipment		148,810,598						251,456,952
Less: Accumulated Depreciation, Depletion and Amortization		(21,217,104	)					(21,217,104	)
Net Property and Equipment		127,593,494						230,239,848
Other Assets
Other Assets—Net		1,239,996			2,094,824	(b)		3,334,820
Long-Term Derivative Instruments		—						—
Total Other Assets		1,239,996						3,334,820
Total Assets	$	139,770,661					$	250,050,426

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REX ENERGY CORPORATION

UNAUDITED PRO FORMA COMBINED CONDENSED BALANCE SHEET—Continued

	March 31, 2007
	Founding Companies Combined			Pro Forma Adjustments for the Offering		Pro Forma as Adjusted
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable and Accrued Expenses	$	8,291,291				$	8,291,291
Short-Term Derivative Instruments		3,205,063					3,205,063
Accrued Distributions		—					—
Lines of Credit		38,630,634		(38,630,634	)(c)		—
Current Portion of Long-Term Debt		11,561,150		(11,561,150	)(c)		—
Related Party Payable		—					—
Total Current Liabilities		61,688,138					11,496,354
Long-Term Liabilities
Long-Term Debt		42,311,563		(42,311,563	)(d)		—
Other Loans and Notes Payable—Long-Term Portion		772,500		(772,500	)(d)		—
Long-Term Derivative Instruments		3,621,976					3,621,976
Participation Liability—Net		2,141,109		(2,141,109	)(d)		—
Other Liabilities		393,218					393,218
Asset Retirement Obligation		5,666,279					5,666,279
Total Long-Term Liabilities		54,906,645					9,681,473
Total Liabilities		116,594,783					21,177,827
Minority Interests		25,399,110		(25,399,110	)(e)		—
Owners’ Equity
Common Stock		1,060		30,134	(f)		31,194
Additional Paid-In Capital		1,460,000		227,381,405	(f)		228,841,405
Accumulated Stockholders’ (Deficit)		(420,322	)	420,322	(f)		—
Partners’ and Members’ (Deficit)		(3,263,970	)	3,263,970	(f)		—
Total Owners’ Equity (Deficit)		(2,223,232	)				228,872,599
Total Liabilities, Minority Interests and Owners’ Equity (Deficit)	$	139,770,661				$	250,050,426

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REX ENERGY CORPORATION

UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF OPERATIONS

	Three Months Ended March 31, 2007
	Founding Companies Combined			Pro Forma Adjustments for the Offering		Pro Forma as Adjusted
OPERATING REVENUE
Oil and Natural Gas Sales	$	12,774,851				$	12,774,851
Other Operating Revenue		100,221					100,221
Realized Gain (Loss) on Hedges		264,838					264,838
Unrealized Gain (Loss) on Hedges		(3,436,845	)				(3,436,845	)
TOTAL OPERATING REVENUE		9,703,065					9,703,065
OPERATING EXPENSES
Production & Lease Operating Expenses		6,105,097					6,105,097
General and Administrative Expense		1,981,995					1,981,995
Accretion Expense on Asset Retirement Obligation		124,210					124,210
Impairment Charge on Oil and Gas Properties		585,042					585,042
Depreciation, Depletion, and Amortization		3,949,049		3,247,441	(g)		7,196,490
TOTAL OPERATING EXPENSES		12,745,393					15,992,834
INCOME (LOSS) FROM OPERATIONS		(3,042,328	)				(6,289,769	)
OTHER INCOME (EXPENSE)
Interest Income		8,917					8,917
Interest Expense		(2,084,820	)	2,084,820	(h)		—
Gain (Loss) on Sale of Oil and Gas Properties		176,482					176,482
Other Income (Expense)		(43,506	)				(43,506	)
TOTAL OTHER INCOME (EXPENSE)		(1,942,927	)				141,893
PRE TAX NET INCOME (LOSS) BEFORE MINORITY INTEREST		(4,985,255	)				(6,147,876	)
MINORITY INTEREST SHARE OF INCOME (LOSS)		(2,727,892	)	2,727,892	(i)		—
PRE TAX NET INCOME (LOSS) AFTER MINORITY INTEREST		(2,257,363	)				(6,147,876	)
Provision for Taxes		—		(2,477,594	)(j)		(2,477,594	)
NET INCOME (LOSS)	$	(2,257,363	)			$	(3,670,282	)

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REX ENERGY CORPORATION

UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF OPERATIONS

	Year Ended December 31, 2006
	Founding Companies Combined			Acquisitions										Pro Forma as Adjusted
				Team Energy Non-Op Properties for Five Months Ended May 30, 2006		Team Energy Properties For Five Months Ended May 30, 2006		TSAR Energy II Properties For Nine Months Ended September 30, 2006		Pro Forma Adjustments for Acquisitions		Pro Forma Adjustments for the Offering
OPERATING REVENUE
Oil and Natural Gas Sales	$	43,596,017		$	205,259	$	3,095,956	$	14,500,898					$	61,398,130
Other Operating Revenue		469,582													469,582
Realized Gain (Loss) on Hedges		(4,436,347	)												(4,436,347	)
Unrealized Gain (Loss) on Hedges		5,043,220													5,043,220
TOTAL OPERATING REVENUE		44,672,472													62,474,585
OPERATING EXPENSES
Production & Lease Operating Expenses		15,234,055			66,460		945,374		7,241,261	(1,599,104	)(k)				21,888,046
General and Administrative Expense		6,212,139								1,408,229	(l)				7,620,368
Accretion Expense on Asset Retirement Obligation		475,501													475,501
Impairment Charge on Oil and Gas Properties		—													—
Depreciation, Depletion, and Amortization		10,746,805								4,636,215	(m)	8,837,474	(g)		24,220,494
TOTAL OPERATING EXPENSES		32,668,500													54,204,409
INCOME (LOSS) FROM OPERATIONS		12,003,972													8,270,176
OTHER INCOME (EXPENSE)
Interest Income		93,684													93,684
Interest Expense		(6,110,023	)									6,110,023	(h)		—
Gain (Loss) on Sale of Oil and Gas Properties		91,416													91,416
Other Income (Expense)		(131,713	)												(131,713	)
TOTAL OTHER INCOME (EXPENSE)		(6,056,636	)												53,387
PRE TAX NET INCOME (LOSS) BEFORE MINORITY INTEREST		5,947,336													8,323,563
MINORITY INTEREST SHARE OF INCOME (LOSS)		2,133,655			74,257		1,150,561		3,629,819			(6,988,292	)(i)		—
PRE TAX NET INCOME (LOSS) AFTER MINORITY INTEREST		3,813,681													8,323,563
Provision for Taxes		—										3,354,396	(j)		3,354,396
NET INCOME (LOSS)	$	3,813,681												$	4,969,167

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UNAUDITED NOTES TO PRO FORMA COMBINED FINANCIAL STATEMENTS

NOTE 1—PRO FORMA ADJUSTMENTS

Pro forma adjustments have been made to the following:

(a) Current assets to account for changes in cash and cash equivalents in accordance with our planned use of proceeds from the offering assuming offering costs of approximately $7.2 million in underwriting discounts and commissions and $1.7 million in offering expenses remaining unpaid as of March 31, 2007, $400,000 of which have been paid subsequent to March 31, 2007; and to Accounts Receivable to reclassify approximately $569,000 in deferred offering costs to a reduction in Paid-in Capital;

(b) Property and equipment and other assets were adjusted upward in the total amount of $104.8 million to account for the estimated increase in book value of our proved properties, unevaluated properties and other assets attributable to the application of purchase accounting to minority interests being acquired in the Reorganization Transactions; this increase has been calculated based on the market value of shares to be owned by the minority interest equity owners, which total 10,845,024 shares, assuming a $12.00 per share offering price less the book value of minority interests of $25.4 million. The total associated increase to assets of $104.8 million has been allocated 71% to our proven properties, 27% to our unevaluated properties and 2% to other assets in accordance with the valuation methodology utilized in establishing the exchange ratios for each of the Founding Companies.

(c) Current liabilities for the repayment of the current portion of long-term debt in accordance with our planned use of proceeds from the offering;

(d) Other long term liabilities for the repayment of a participation liability in the amount of $2,141,109 to an unrelated party in accordance with our planned use of proceeds from the offering. Long-term debt net of current maturities for the repayment of the senior debt facilities of the Founding Companies and certain other notes payable to unrelated parties in accordance with our planned use of proceeds from the offering;

(e) Minority interests to account for the acquisition of these minority interests for shares of our common stock upon consummation of this offering, which include 94.8% of Rex Royalties, 86.3% of Douglas Oil & Gas, 86.3% of Douglas Westmoreland, 97.5% of Midland Exploration, 77.7% of Rex I, 88.9% of Rex II, 100% of Rex II Alpha, 53.5% of Rex III, 50% of Rex IV, 59.96% of New Albany and 40% of Rex Operating equity interests;

(f) Represents adjustments to Owners’ Equity to reflect pro forma shareholders’ equity of Rex Energy Corporation, reflecting the acquisition of minority interests in the Founding Companies by the issuance of 10,845,024 shares by Rex Energy Corporation, and the issuance of 9,200,000 shares by Rex Energy Corporation in the initial public offering, in each case assuming an initial public offering price per share of $12.00. Aggregate adjustments to equity include:

• $110.4 million in gross proceeds from the initial public offering, less (i) $7.2 million in underwriting discounts and commissions, (ii) $569,000 to reclassify deferred offering costs from current assets and (iii) estimated additional offering expenses of $1.7 million; plus

• the acquisition cost of minority interests of $130.1 million less eliminations of historical equity book value of the acquired interests of $25.4 million.

These aggregate adjustments were made to the individual equity accounts as follows:

• an allocation of value to Common Stock to reflect aggregate common stock par value of $31,194,702 pro forma shares outstanding;

• the elimination of Accumulated Shareholders’ Deficit and Partners’ and Members’ Deficits of the Founding Companies; and

• the allocation of the remainder of the adjustment to Additional Paid-In Capital.

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(g) Depreciation and Depletion to account for the increase in the book value of our assets associated with applying purchase accounting to the acquisition of minority interests. Depreciation and depletion have been adjusted upward from the prior period end based upon the proportionate increase in evaluated, or proved, property book value associated with the application of purchase accounting to the acquisition of minority interests.

(h) Interest to account for the repayment of all credit facilities of the Founding Companies in accordance with our planned use of proceeds from the offering; and

(i) Minority interests to account for the acquisition of minority interests;

(j) An estimate for a provision for federal and state income taxes for the period calculated as 40.3%, our estimated effective state and federal income tax rate, of Pre-Tax Net Income After Minority Interest.

(k) Lease operating expenses to deduct overhead expenses which were included in lease operating expenses of Team Energy, L.L.C. in the amount of $190,875 and TSAR Energy II, L.L.C. in the amount of $1,408,229 for the periods prior to the date on which we acquired the properties;

(l) General and administrative expenses to deduct overhead fees received from TSAR Energy II, L.L.C. in the amount of $1,408,229 for the period prior to the date on which we acquired the properties. This reduction in overhead fees effectively increases our total net general and administrative expenses;

(m) Depreciation and depletion to account for the Team Energy, L.L.C. properties in the amount of $1,442,771 and the TSAR Energy II, L.L.C. properties in the amount of $3,193,444 for the period prior to the date we acquired the properties;

Reconciliation of Pro Forma Non-GAAP Financial Measure

We disclose pro forma EBITDAX Before Minority Interests in this prospectus. This may be viewed as a non-GAAP financial measure. For an explanation of how our management uses EBITDAX, please read “Selected Historical Financial and Operating Data—Non-GAAP Financial Measures—EBITDAX.”

	Three Months Ended March 31,						For the Year Ended December 31,
	2007 (Actual)			2007 (Pro forma)			2006 (Actual)		2006 (Pro forma)
Pre-Tax Net Income (Loss) Before Minority Interests	$	(4,985,255	)	$	(6,147,876	)	$	5,947,336	$	8,323,563
Add Back Depletion, Depreciation & Amortization		4,073,259			7,320,700			11,222,306		24,695,995
Add Back Interest Expense		2,084,820			—			6,110,023		—
Add Back Exploration & Impairment Expense		585,042			585,042			—		—
Less Interest Income		8,917			8,917			93,684		93,684
Less Unrealized Gains (Losses) from Financial Derivatives		(3,436,845	)		(3,436,845	)		5,043,220		5,043,220
EBITDAX Before Minority Interests	$	5,185,794		$	5,185,794		$	18,142,761	$	27,882,654

The audited historical financial statements of each of the Founding Companies are included beginning on page F-115 of this prospectus. You should review such information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited summary historical financial and operating data and related notes included elsewhere in this prospectus.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The historical combined financial statements included elsewhere in this prospectus reflect the operations of the Founding Companies, which collectively are our predecessor. The following discussion analyzes the historical financial condition and results of operations of the Founding Companies on a combined basis. You should read the following discussion of the historical financial condition and results of operations of the Founding Companies in conjunction with the historical combined financial statements of the Founding Companies and the related notes thereto, and the unaudited pro forma financial statements of Rex Energy Corporation, each included elsewhere in this prospectus. These summary combined historical financial results may not be indicative of our future financial or operating results.

The following discussion and analysis should be read in conjunction with the “Selected Historical Financial Data” and the consolidated financial statements and related notes included elsewhere in this prospectus. This discussion contains forward-looking statements reflecting our current expectations and estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” appearing elsewhere in this prospectus.

Overview

We are an independent oil and gas company operating in the Illinois Basin, Appalachian Basin and southwestern region of the United States. We pursue a balanced growth strategy of exploiting our sizeable inventory of lower risk developmental drilling locations, pursuing our higher potential exploration drilling prospects and actively executing our acquisition strategy.

We are one of the largest oil producers in the Illinois Basin, with first quarter 2007 average net production of 2,127 barrels of oil per day from approximately 1,412 gross producing wells. In addition to our production in the Illinois Basin, we have acquired, or have an option to acquire, over 270,000 gross acres in southern Indiana, which we believe are prospective for New Albany Shale exploration and development. We are also developing an enhanced oil recovery, or EOR, project in the Lawrence Field in Lawrence County, Illinois, which we refer to as our Lawrence Field ASP Project. At December 31, 2006, we operated approximately 2,150 wells, representing approximately 95% of our total proved reserves. For the quarter ended March 31, 2007, we produced an average of 2,770 net BOE per day, comprised of approximately 81% oil and approximately 19% natural gas.

In our Appalachian region we own approximately 544 gross producing natural gas wells with first quarter 2007 average net production of 2.2 MMcf of natural gas per day, and in our Southwestern region we own 118 gross producing wells in Texas and New Mexico with first quarter 2007 average net production of 1.6 MMcfe per day with several active drilling projects in both areas.

We are headquartered in State College, Pennsylvania, and have regional offices in Canonsburg (Pittsburgh), Pennsylvania, Midland, Texas and Bridgeport, Illinois.

Our financial results depend upon many factors, particularly the price of oil and gas. Commodity prices are affected by changes in market demand, which is impacted by overall economic activity, weather, refinery or pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future oil and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success.

48

How We Generate Our Revenue

We generate our revenue primarily from the sale of crude oil to refining companies and natural gas to local distribution and pipeline companies. Our operating revenue before the effects of financial derivatives from these operations, and their relative percentages of our total revenue, consisted of the following:

	Year Ended December 31,
	2006		% of Total		2005		% of Total		2004		% of Total
Revenue from Crude Oil Sales	$	35,789,655	81.2	%	$	20,354,195	68.3	%	$	7,833,066	52.7	%
Revenue from Natural Gas Sales		7,806,362	17.7	%		9,163,395	30.8	%		6,325,846	42.6	%
Other		469,582	1.1	%		270,140	0.9	%		697,412	4.7	%
Total	$	44,065,599	100.0	%	$	29,787,730	100.0	%	$	14,856,324	100.0	%

	Three Months Ended March 31,
	2007		% of Total		2006		% of Total
Revenue from Crude Oil Sales	$	10,873,506	84.5	%	$	6,616,630	71.2	%
Revenue from Natural Gas Sales		1,901,344	14.8	%		2,552,161	27.5	%
Other		100,222	0.7	%		127,143	1.3	%
Total	$	12,875,072	100.0	%	$	9,295,934	100.0	%

We have identified the impact of generally higher commodity prices in the last several years as compared with prior periods as an important trend that we expect to affect our business in the future. If commodity prices continue at present relatively high levels or increase, we would expect this trend to result not only in increased revenue, but also in an increasingly competitive environment for quality drilling prospects, qualified geological and technical personnel and oil field services, including rig availability. Increasing competition in these areas, which we expect to increase so long as commodity prices remain relatively high, will likely result in higher costs in these areas, and could result in unavailability of drilling rigs, thus affecting the profitability of our future operations. We may not be able to compete successfully in the future with larger competitors in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. In the event of a declining commodity price environment, our revenues would decrease and we would anticipate that the cost of materials and services would decrease as well, although at a slower rate. Decreasing oil or natural gas prices may also make some of our prospects uneconomic to drill.

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include EBITDAX, lease operating expenses per BOE, growth in our proved reserve base and general and administrative expenses as a percentage of revenue.

EBITDAX

“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized losses from financial derivatives, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX as defined above is used as a financial measure by our management team and by other users of our financial statements such as our commercial bank lenders.

• Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial or capital structure;

• The financial performance of our assets and valuation of the entity without regard to financing methods, capital structure or historical cost basis;

49

• Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and

• The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Lease Operating Expenses per BOE

Lease operating expenses are comprised of those expenses which are directly attributable to our producing oil and gas leases, including state and county production taxes, production related insurance, the cost of materials, maintenance, electricity, chemicals, fuel and the wages of our field personnel. Our lease operating expenses per BOE are higher than those of many of our peers primarily because of the nature of our oil properties, many of which are mature waterflood properties. As we continue to develop our non-proved properties, we believe this metric will continue to decrease on a per unit basis. Our goal is to reduce our lease operating expenses per BOE produced from our average cost in 2006 per BOE of $19.72 to below $15.00 per BOE through our anticipated production growth in properties with lower operating costs.

Growth in our Proved Reserve Base

We measure our ability to grow our proved reserves over the amount of our total annual production. As we produce oil and gas attributable to our proved reserves, our proved reserves decrease each year by that amount of production. We attempt to replace these produced proved reserves each year through the addition of new proved reserves through our drilling and other property improvement projects and through acquisitions. Our proved reserves have risen significantly since 2004, from 4.1 MMBOE at year end 2004 to 9.1 MMBOE at year end 2005 to 14.5 MMBOE at year end 2006. Our reserve replacement ratio for year end 2005 was approximately 833% based on an increase in total proven reserves of 5 MMBOE, total production for the year of 577 MBOE, proven reserve divestitures of 400 MBOE, purchases of reserves of 4.4 MMBOE, extensions discoveries and other additions of 11 MBOE, and revisions of previous estimates of 1.5 MMBOE. Our reserve replacement ratio for year end 2006 was approximately 675% based on an increase in total proven reserves of 5.5 MMBOE, total production for the year of 770 MBOE, purchases of reserves of 6.7 MMBOE, extensions discoveries and other additions of 198 MBOE, and revisions of previous estimates of negative 700 MBOE.

General and Administrative Expenses as a Percentage of Oil and Gas Revenue

Our general and administrative expenses include fees for well operating services, marketing, non-field level employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our general and administrative expenses in relation to our revenue because these expenses have a direct impact on our profitability. Our general and administrative expenses as a percentage of oil and gas revenue decreased in 2005 to 12.8% from 15.7% in 2004, and grew to 14.2% in 2006. Although we anticipate our general and administrative expenses will increase over the next two years as a result of additional administrative expenses associated with being a public company and our anticipated growth, our goal is to reduce our general and administrative expenses as a percentage of our revenue to below 10% through an increase in our production while endeavoring to limit growth in our overhead expenses.

Our general and administrative expenses will increase in connection with the completion of this offering. This increase will be due primarily to the cost of accounting support services, filing annual and quarterly reports with the SEC, investor relations, directors’ fees, directors’ and officers’ insurance, and registrar and transfer agent fees. This increase will also consist of legal and accounting fees and additional expenses associated with compliance with the Sarbanes-Oxley Act of 2002 and other regulations. As a result, we believe that our general and administrative expenses for future periods will increase significantly. Our consolidated financial statements following the completion of this offering will reflect the impact of these increased expenses and affect the comparability of our financial statements with periods prior to the completion of this offering.

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Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon the combined financial statements of the Founding Companies, which have been prepared in accordance with accounting policies generally accepted in the United States. The preparation of our combined financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our combined financial statements. Described below are the most significant policies we apply in preparing our combined financial statements some of which are subject to alternative treatments under accounting policies generally accepted in the United States. We also describe the most significant estimates and assumptions we make in applying these policies. Please read the notes to the financial statements under the heading “Summary of Significant Accounting Policies” for additional accounting policies and estimates by management.

Oil and Gas Activities

Accounting for oil and gas activities is subject to special, unique rules. We utilize the successful efforts method for accounting for our oil and gas activities. The significant principles for this method are:

• Geological and geophysical evaluation costs are expensed as incurred;

• Dry holes for exploratory wells are expensed. Dry holes for developmental wells are capitalized; and

• Impairments of properties, if any, are based on the evaluation of the carrying value of properties against their fair value based upon pools of properties grouped by geographical and geological conformity.

Our engineering estimates of proved oil and gas reserves directly impact financial accounting estimates including depletion, depreciation, and amortization expense; evaluation of impairment of properties and the calculation of plugging and abandonment liabilities. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for any reservoir may change substantially over time as a result of changing results from operational activity and results. Changes in commodity prices, operation costs and techniques will also change and change the overall evaluation of reservoirs.

Our proved reserves increased 59% in 2006 over 2005, growing to 14.5 MMBOE from 9.1 MMBOE. In 2005, our proved reserves increased 122% from 4.1 MMBOE to 9.1 MMBOE. As of December 31, 2006, we had 257 gross (247 net) proved undeveloped drilling locations and 252 gross (242 net) wells with proved developed non-producing reserves. The following table summarizes our proved reserves as of December 31, 2004, 2005 and 2006:

	Year Ended December 31,
	2006			2005			2004
Total MMBOE		14.5			9.1			4.1
% Oil		80	%		70	%		49	%
PV-10 (millions)	$	200.3		$	148.1		$	43.7
Pro forma Standardized Measure (millions)	$	132.1		$	108.2		$	40.2
WTI Price Assumption Used	$	57.75		$	57.75		$	30.35
Henry Hub Price Assumption Used	$	5.64		$	10.08		$	6.18

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Our estimated proved reserves as of December 31, 2005 and 2006 are based on reserve evaluation reports prepared by Netherland, Sewell & Associates, Inc. Our estimated proved reserves as of December 31, 2004 were prepared internally.

Derivative Instruments

We enter into derivative contracts associated with future crude oil and natural gas prices. We do not designate our derivative instruments as cash flow hedges, and as such we classify our derivative instruments as either realized and unrealized gains, or losses, on the effective portion of the derivative to earnings when the underlying transaction occurs.

Asset Retirement Obligations

We are required by SFAS 143 “Accounting for Asset Retirement Obligations” to estimate the present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We compute our liability for asset retirement obligations by calculating the present value of estimated future cash flows related to each property. This requires us to use significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations.

Our asset retirement obligations are amortized based upon units of production of proved reserves attributable to the properties to which the obligations relate. Some of these obligations relate to an individual or a group of producing wells and are amortized based on proved producing reserves attributable to that well or group of wells. Other asset retirement obligations may relate to an entire field or area that is not fully developed. Because these obligations relate to assets installed to service future development, they are amortized based on all proved reserves attributable to the field or area.

Effects of Estimates and Assumptions on Financial Statements

Generally accepted accounting principles do not require, or even permit, the restatement of previously issued financial statements due to changes in estimates unless such estimates were unreasonable or did not comply with applicable SEC accounting rules. We are required to use our best judgment in making estimates and assumptions, taking into consideration the best and most current data available to us at the time of the estimate. At each accounting period, we make a new estimate using new data, and continue the cycle. You should be aware that estimates prepared at various times may be substantially different due to new or additional information. While an estimate made at one point in time may differ from an estimate made at a later date, both may be proper due to the differences in available information or assumptions. In this section, we will discuss the effects of different estimates on our financial statements.

Provision for Depletion, Depreciation and Amortization

We calculate depletion, depreciation and amortization using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped

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leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

Impairment of Unproved Properties

Each quarter, we review our unproved oil and gas properties to determine if there has been, in our judgment, an impairment in value of each prospect that we consider individually significant. To the extent that the carrying cost of a prospect exceeds its estimated value, we make a provision for impairment of unproved properties, and record the provision as abandonments and impairments within exploration costs on our statement of operations. If the value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the prospect at a net cost that is lower than its estimated value. If the value is revised downward in a future period, an additional provision for impairment is made in that period. We do not escalate valuations of our unproved oil and gas properties above the NYMEX strip.

Impairment of Proved Properties

Each quarter, we assess our producing properties for impairment. If we determine there has been an impairment in any of our producing properties (or appropriate groups of properties based on geographical and geological similarities), we will estimate the value of each affected property. In accordance with applicable accounting standards, the value for this purpose is a fair value instead of a standardized reserve value as prescribed by the SEC. We attempt to value each property using reserve classifications and pricing parameters similar to what a willing seller and willing buyer might use. These parameters may include escalations of prices instead of constant pricing, and they may also include the risk-adjusted value of reserves that do not qualify as proved reserves. To the extent that the carrying cost for the affected property exceeds its estimated value, we make a provision for impairment of proved properties. If the value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the property at a net cost that is lower than its estimated value. If the value is revised downward in a future period, an additional provision for impairment is made in that period. Accordingly, the carrying costs of producing properties on our balance sheet will vary from (and often will be less than) the present value of proved reserves for these properties.

Recent Accounting Pronouncements

On December 16, 2004, the Financial Accounting Standards Board (“FASB”) published Statement of Financial Accounting Standards No. 123 (Revised 2004), “Share Based Payment” (“SFAS 123(R)”). SFAS 123(R) requires that compensation cost related to share based payment transactions be recognized in the financial statements. Share based payment transactions within the scope of SFAS 123(R) include stock options, restricted stock plans, performance based awards, stock appreciation rights, and employee share purchase plans. The provisions of SFAS 123(R) were effective for us as of the first annual reporting period beginning after December 15, 2005. Accordingly, we implemented the revised standard in the first quarter of 2006.

In March 2005, the FASB issued FASB Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement Obligations. This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, Accounting for Asset Retirement Obligations (FAS 143). A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside our control. FIN 47 states that we must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This interpretation is intended to provide more information about long-lived assets, future cash outflows for these obligations, and more consistent recognition of these liabilities. FIN 47 is effective for

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fiscal years ending after December 15, 2005; accordingly, we implemented the interpretation in 2006. We do not believe that our financial position, results of operations or cash flows will be impacted by this Interpretation.

In February 2006, the FASB issued FAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (“FAS 155”). FAS 155 eliminates the exemption from applying FASB Statement No. 133 to interests in securitized financial assets. FAS 155 is effective for the first fiscal year end that begins after September 15, 2006, which for us will be January 1, 2007. We do not believe adoption of FAS 155 will have a material impact on our financial position or results of operations.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 will become effective for us on January 1, 2007. We are currently evaluating the impact of adopting FIN 48 on our financial position and results of operations.

In September 2006, the FASB issued FAS No. 157, “Fair Value Measurements” (“FAS 157”). FAS 157 defines fair value to measure assets and liabilities, establishes a framework for measuring fair value, and requires additional disclosures about the use of fair value. FAS 157 is applicable whenever another accounting pronouncement requires or permits assets and liabilities to be measured at fair value. FAS 157 does not expand or require any new fair value measures. FAS 157 is effective for our fiscal year beginning January 1, 2008. We are currently evaluating the impact that the adoption of FAS 157 will have on our financial position or results of operations.

In September 2006, the FASB issued FASB No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB No. 87, 88, 106 and 132(R).” FASB No. 158 improves financial reporting by requiring an employer to recognize the over funded or under funded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. This Statement also improves financial reporting by requiring an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. FASB No. 158 is effective as of the fiscal year ending after December 15, 2006. We do not believe the impact of FASB No. 158 will be material to our results of operations.

In September 2006, the SEC issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides guidance on the consideration of effects of the prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. The SEC staff believes registrants must quantify errors using both a balance sheet and income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. SAB 108 is effective for the first annual period ending after November 15, 2006 with early application encouraged; accordingly, we adopted this interpretation in the fourth quarter of 2006. We do not believe the impact of FASB No. 158 will be material to our results of operations.

In February 2007, the FASB issued FAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“FAS 159”). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. FAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007, which for us will be January 1, 2008.

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Results of Operations

During 2005 we completed five significant acquisitions of producing properties, which impacted our reserves, revenues and operations over that realized in 2004.

In January 2005, we acquired the stock of ERG Illinois, Inc., whose assets included average working interests of 26% in the Lawrence, West Kenner, St. James and El Nora fields in the Illinois Basin, for approximately $5.0 million. Prior to this acquisition, we owned a 25% non-operated working interest in these fields, and this acquisition gave us the operating rights to the fields. The properties added 2.0 MMBOE to our proved reserves. During the period we owned the properties in 2005, they produced total oil and gas revenues of $9.1 million before the effects of financial derivatives, or approximately 31% of our total oil and gas revenues for the year, and had $5.1 million in total operating expenses, or approximately 44% of our total operating expenses.

In July 2005, we acquired average working interests of 100% in approximately 17 wells and related infrastructure in Lawrence County, Illinois for approximately $1.3 million. The properties added 170 MBOE to our proved reserves. During the period we owned the properties in 2005, they produced total oil and gas revenues of $277,000 before the effects of financial derivatives, or approximately 1% of our total oil and gas revenues for the year, and had $59,000 in total operating expenses, or approximately 1% of our total operating expenses.

In August 2005, we acquired average working interests of 33% in approximately 13 wells and related infrastructure in Lea and Eddy Counties, New Mexico for approximately $3.6 million. The properties added 459 MBOE to our proved reserves. During the period we owned the properties in 2005, they produced total oil and gas revenues of $26,900 before the effects of financial derivatives, or less than 1% of our total oil and gas revenues for the year, and had $10,700 in total operating expenses, or less than 1% of our total operating expenses.

In September 2005, we acquired average working interests of 100% in approximately 23 wells and related infrastructure in Lawrence County, Illinois for approximately $750,000. The properties added 147 MBOE to our proved reserves. During the period we owned the properties in 2005, they produced total oil and gas revenues of $102,000 before the effects of financial derivatives, or less than 1% of our total oil and gas revenues for the year, and had $46,000 in total operating expenses, or less than 1% of our total operating expenses.

In December 2005, we acquired average working interests of 100% in approximately 52 wells and related infrastructure in Lawrence County, Illinois for approximately $7.0 million. The properties added 832 MBOE to our proved reserves. During the period we owned the properties in 2005, they produced total oil and gas revenues of $258,000 before the effects of financial derivatives, or approximately 1% of our total oil and gas revenues for the year, and had $35,000 in total operating expenses, or less than 1% of our total operating expenses.

During 2006 we completed four significant acquisitions, which substantially changed the magnitude of our operations and resulted in substantially increased production volumes, revenues and expenses over those realized in 2005.

In January 2006, we acquired average working interests of 99.5% in approximately 21 producing oil wells and related infrastructure in Glassrock, Midland, Reagan and Upton Counties, Texas, for approximately $5.2 million from Westar Energy, Inc., effective January 1, 2006. The properties added 512 MBOE to our proved reserves. During the period we owned the properties in 2006, they produced total oil and gas revenues of $1.3 million, or approximately 3% of our total oil and gas revenues for the year, and had $420,000 in total operating expenses, or approximately 3% of our total operating expenses.

In February 2006, we acquired average working interests of 49.8% in approximately 15 producing gas wells and a related gathering system in Terrell County, Texas for approximately $3.8 million from Wadi Petroleum, Inc., effective January 1, 2006. The properties added 154 MBOE to our proved reserves. During the period we owned the properties in 2006, they produced total oil and gas revenues of $552,000, or approximately 1.3% of

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our total oil and gas revenues for the year, and had $132,000 in total operating expenses, or approximately 1% of our total expenses.

In June 2006, we acquired average working interests of 72% in approximately 177 producing oil wells and related infrastructure in Posey and Gibson Counties, Indiana and Lawrence County, Illinois for approximately $22.7 million from Team Energy, L.L.C. and certain of its affiliates. The properties added 1.84 MMBbls to our proved reserves. For the seven months we owned the properties during 2006, they produced total oil and gas revenues of $4.3 million or 10% of our total oil and gas revenues for the year and had $1.2 million in total operating expenses or 8% of our total operating expenses.

In October 2006, we acquired average working interests of 49% in the Lawrence, West Kenner, and St. James fields in Illinois, and the El Nora field in Indiana for approximately $35.2 million from TSAR Energy II, L.L.C. We own and operate the remaining 51% working interests in the fields which we acquired in 2004 and 2005. The properties added 3.85 MMBbls to our proved reserves. During the period we owned the properties in 2006, they produced total oil and gas revenues of $4.0 million, or 9% of our total oil and gas revenues for the year, and had $2.4 million in total operating expenses, or 17% of our total operating expenses.

Operating Results for the Three Months Ended March 31, 2007 and 2006 and the Years Ended December 31, 2006, 2005 and 2004

	Three Months Ended March 31,						Year Ended December 31,
	2007			2006			2006			2005			2004
Net Oil Production (Mbbls)		201.4			113.4			587			379			197
Average Sales Price (per Bbl)	$	53.98		$	58.33		$	60.92		$	53.71		$	39.67
Net Gas Production (per MMcf)		287.0			294.0			1,109			1,126			1,067
Average Sales Price (Mcf)	$	6.63		$	8.68		$	7.04		$	8.15		$	5.93
Total Net Production (Mboe)		249.2			162.4			772			566			375
Average Sales Price (per Boe)	$	51.25		$	56.45		$	56.44		$	52.11		$	37.72
Operating Revenues (in thousands)
Natural Gas and Oil Production Revenues	$	12,775		$	9,169		$	43,596		$	29,518		$	14,159
Realized Gain (Loss) on derivatives		265			(1,390	)		(4,436	)		(7,929	)		(942	)
Unrealized gain (loss) on derivatives		(3,437	)		120			5,043			(5,541	)		(1,396	)
Other Revenues		100			126			470			270			697
Total Operating Revenues		9,703			8,025			44,673			16,318			12,518
Operating Expenses (in thousands)
Production and Lease Operating		6,105			2,443			15,234			11,721			6,708
General and Administrative		1,982			843			6,212			3,789			2,229
Depletion, Depreciation and Amortization		4,073			2,065			11,222			3,320			2,039
Asset Impairment		585			—			—			107			3,024
Total Operating Expense		12,745			5,351			32,669			18,937			14,000
Other Income (Expense)
Interest Income		9			36			94			444			19
Interest Expense		(2,085	)		(766	)		(6,110	)		(1,697	)		(867	)
Gain on Sale or Disposal of Oil and Gas Properties		176			—			91			1,017			659
Other income (expense)		(44	)		(113	)		(132	)		216			(21	)
Total Other Income		(1,943	)		(843	)		(6,057	)		(21	)		(211	)
Net Income (Loss) Before Minority Interests		(4,985	)		1,829			5,947			(2,641	)		(1,692	)
Minority Interest Share of Income (Loss)		(2,728	)		921			2,134			2,304			(2,062	)
Net Income	$	(2,257	)	$	908		$	3,814		$	(4,945	)	$	370

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Three Months Ended March 31, 2007 Compared with the Three Months Ended March 31, 2006

Net Income. Net income decreased from $908,000 in the three months ended March 31, 2006 to a loss of $2.3 million in the three months ended March 31, 2007. Net Income before Minority Interests decreased from $1.8 million in the three months ended March 31, 2006 to a loss of $4.9 million in the three months ended March 31, 2007. Minority Interest Share of Income decreased from $921,000 in the three months ended March 31, 2006 to a loss of $2.7 million in the three months ended March 31, 2007.

Oil and Gas Sales. Oil and gas sales increased from $9.2 million in the three months ended March 31, 2006 to $12.8 million in the three months ended March 31, 2007 as a result of increased production from acquisitions made during 2006 and the success of our 2006 drilling and workover programs. The acquisitions completed during 2006 were the most significant factor in the increased oil and gas revenue. In addition, the average price of oil received by us, which accounted for approximately 71% of our revenue in the three months ended March 31, 2006, and 85% of our revenue in the three months ended March 31, 2007, also impacted our overall revenues. The average price for natural gas received by us decreased 24% from $8.68 per Mcf in the three months ended March 31, 2006 to $6.63 per Mcf in the three months ended March 31, 2006, and the average price for oil received by us decreased 7.5% from $58.33 per Bbl in the three months ended March 31, 2006 to $53.98 per Bbl in the three months ended March 31, 2007.

Derivative Activities. We enter into derivative contracts associated with future crude oil and natural gas prices. We do not designate our derivative instruments as cash flow hedges, and as such, we classify our derivative instruments as either realized and unrealized gains, or losses, on the effective portion of the derivative to earnings when the underlying transaction occurs. During the three months ended March 31, 2006, we incurred realized losses of $1.4 million from our oil and gas derivatives and unrealized losses of $120,000. During the three months ended March 31, 2007, we realized a gain of $265,000 and unrealized losses of $3.4 million from our oil and gas derivatives.

Lease Operating Expense. Lease operating expense increased $3.7 million in the first quarter of 2007 over the first quarter of 2006 due primarily to the acquisitions we completed during 2005 and 2006. Our average lease operating expense per BOE increased from $15.04 in the first quarter of 2006 to $24.49 in first quarter of 2007. Our production increased 53% and our lease operating expenses increased 150% in the first quarter of 2007 over the first quarter of 2006. The increase in our average lease operating expenses per BOE was caused primarily by our acquisitions of properties during 2006 in the Illinois Basin, which consisted of producing waterflood properties with higher per unit operating costs.

DD&A Expense. We had increased production in the first quarter of 2007 from our acquisitions and drilling programs in 2006, which was reflected in an increased DD&A expense from $2.1 million in the first quarter of 2006 to $4.1 million in the first quarter of 2007. In addition, the DD&A expense per unit of production increased from $12.71 per BOE in the first quarter of 2006 to $16.34 per BOE in the first quarter of 2007. The significant increase in DD&A per BOE was caused primarily by our Team Energy and TSAR Energy acquisitions completed in June and October 2006, respectively, which had a higher per unit basis than previously owned properties, causing the DD&A per unit of production to increase.

General and Administrative Expense (“G&A expense”). G&A expense increased $1.1 million from the first quarter of 2006 to the first quarter of 2007. The increase in G&A expense was principally due to our acquisition of non-operated working interests from TSAR Energy II in October 2006. We operated the fields in which TSAR Energy II owned an interest prior to the acquisition. As a result of this acquisition, the amount of overhead fees we received from third parties was reduced, which was recorded as a deduction of our G&A expense. This reduction in overhead fees accounted for approximately 34% of the $1.1 million increase. In addition, our G&A expenses increased as a result of increased legal expenses associated with our H₂S matter, increases in the number of our employees and other expenses associated with our growth.

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Interest Expense. Interest expense increased $1.3 million to $2.1 million in the first quarter of 2007 from $766,000 in the first quarter of 2006. The significant increase resulted primarily from increased borrowings associated with our 2006 acquisitions.

Income Taxes. Because each of the Founding Companies was taxed as a partnership for federal and state income taxes, we did not pay income taxes in 2006 or in the first quarter of 2007.

Year Ended December 31, 2006 Compared with Year Ended December 31, 2005

Net Income. Net income increased from a loss of $4.9 million in 2005 to income of $3.8 million in 2006. Net Income before Minority Interests increased from a loss of $2.6 million in 2005 to income of $5.9 million in 2006. Minority Interest Share of Income decreased from $2.3 million in 2005 to $2.1 million in 2006.

Oil and Gas Sales. Oil and gas sales increased from $29.5 million in 2005 to $43.6 million in 2006 as a result of increased production from acquisitions made during 2006 and the success of our 2005 and 2006 drilling programs with 94 gross (50 net) successful wells out of a total of 100 gross wells drilled (53 net). The acquisitions completed during 2006, which contributed to a 37% increase in daily production for 2006 compared with 2005, were the most significant factor in the increased oil and gas revenue. In addition, the average price of oil received by us, which accounted for approximately 81% of our revenue in 2006, also impacted our overall revenues. While the average price for natural gas received by us decreased 16% from $8.14 per Mcf in 2005 to $7.04 per Mcf in 2006, the average price for oil received by us increased 14% from $53.71 per Bbl in 2005 to $60.92 per Bbl in 2006.

Derivative Activities. We enter into derivative contracts associated with future crude oil and natural gas prices. We do not designate our derivative instruments as cash flow hedges, and as such we classify our derivative instruments as either realized and unrealized gains, or losses, on the effective portion of the derivative to earnings when the underlying transaction occurs. During 2005, we incurred realized losses of $7.9 million from our oil and gas derivatives, and unrealized losses of $5.5 million. During 2006, we incurred realized losses of $4.4 million and unrealized gains of $5.0 million from our oil and gas derivatives.

Lease Operating Expense. Lease operating expense increased $3.5 million in 2006 over 2005 due primarily to the acquisitions we completed during 2005 and 2006. Our average lease operating expense per BOE decreased from $20.69 in 2005 to $19.72 in 2006. Our production increased 37% and our lease operating expenses increased 30% in 2006 over 2005. The decrease in our average lease operating expenses per BOE was caused primarily by an increase in our total production due to our acquisitions of properties with lower per unit operating costs.

DD&A Expense. We had increased production in 2006 from our acquisitions and drilling programs in 2005 and 2006, which was reflected in an increased DD&A expense from $3.3 million in 2005 to $11.2 million in 2006. In addition, the DD&A expense per unit of production increased from $5.86 per BOE in 2005 to $14.53 per BOE in 2006. The significant increase in DD&A per BOE was caused primarily by our Team Energy and TSAR Energy acquisitions completed during 2006 which had a higher per unit basis than previously owned properties, causing the DD&A per unit of production to increase.

General and Administrative Expense (“G&A expense”). G&A expense increased $2.4 million from 2005 to 2006. The increase in G&A expense was principally due to increases in legal expenses associated with a lawsuit which was settled in October 2006, increased legal expenses associated with our H₂S matter, and increases in the number of employees we had and other expenses associated with our growth. In addition, the acquisition of non-operated working interests associated with the TSAR Energy II acquisition, which we operated prior to the acquisition, reduced the amount of overhead fees we received from third parties which were recorded as a deduction of our G&A expense. This reduction in overhead fees accounted for approximately 20% of the $2.4 million increase.

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Interest Expense. Interest expense increased $4.4 million to $6.1 million in 2006 from $1.7 million in 2005. The significant increase resulted from increased borrowings associated with our 2006 acquisitions.

Income Taxes. Because each of the Founding Companies was taxed as a partnership for federal and state income taxes, we did not pay income taxes in 2005 or in 2006. We have recorded a provision for income taxes of $6.9 million in our combined pro forma income statement for 2006.

Year Ended December 31, 2005 Compared with Year Ended December 31, 2004

Net Income. Net income decreased from $370,000 in 2004 to a loss of $4.9 million in 2006. Net Income before Minority Interests decreased from a loss of $1.7 million in 2004 to a loss of $2.6 million in 2005. Minority Interest Share of Income increased from a loss of $2.1 million in 2004 to income of $2.3 million in 2005.

Oil and Gas Sales. Oil and gas sales increased from $14.2 million in 2004 to $29.5 million in 2005 as a result of increased production from acquisitions made during 2005 and the success of our 2004 and 2005 drilling programs with 24 gross (10 net) successful wells out of a total of 24 gross wells drilled (10 net). The average price for natural gas received by us increased from $5.93 per Mcf in 2004 to $8.14 per Mcf in 2005. The average price for oil received by us also increased from $39.67 per Bbl in 2004 to $53.71 per Bbl in 2005.

Derivative Activities. We enter into derivative contracts associated with future crude oil and natural gas prices. We do not designate our derivative instruments as cash flow hedges, and as such we classify our derivative instruments as either realized and unrealized gains, or losses, on the effective portion of the derivative to earnings when the underlying transaction occurs. During 2004, we incurred realized losses of $942,000 from our oil and gas derivatives, and unrealized losses of $1.4 million. During 2005, we incurred realized losses of $7.9 million and unrealized losses of $5.5 million from our oil and gas derivatives.

Lease Operating Expense. Lease operating expense increased $5.0 million in 2005 over 2004 primarily due to the acquisitions we completed during 2005 and 2004. Our average lease operating expense per BOE in 2005 was $20.69, compared with $17.89 in 2004. Our production and lease operating expenses increased 51% and 74%, respectively, in 2005 over 2004. The increase in our average lease operating expenses per BOE was caused primarily by our acquisition of ERG Illinois, Inc., which owned mature waterflooded properties with higher per unit operating costs than many of our previous properties.

DD&A Expense. We had increased production in 2005 from our acquisitions and drilling programs in 2004 and 2005, which was reflected in an increased DD&A expense from $2.0 million in 2004 to $3.3 million in 2005. In addition, the DD&A expense per unit of production increased from $5.44 per BOE in 2004 to $5.86 per BOE in 2005.

General and Administrative Expense. General and administrative expense increased $1.5 million from 2004 to 2005. The increase in general and administrative expense was principally due to increases in legal expenses associated with a lawsuit which was settled in October 2006, increases in our number of employees and other expenses associated with our growth.

Interest Expense. Interest expense increased $830,000 to $1.7 million in 2005 from $867,000 in 2004. The significant increase resulted from increased borrowings associated with our 2005 acquisitions.

Income Taxes. Because each of the Founding Companies was taxed as a partnership for federal and state income taxes, we did not pay income taxes in 2004 or in 2005.

Capital Resources and Liquidity

Our primary financial resource is our base of oil and gas reserves. We pledge our producing oil and gas properties to a group of banks to secure our senior credit facilities. The banks establish a borrowing base by

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making an estimate of the collateral value of our oil and gas properties. We borrow funds on the senior credit facilities as needed to supplement our operating cash flow as a financing source for our capital expenditure program. Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves. If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. The effects of product prices on cash flow can be mitigated through the use of commodity derivatives. If we are unable to replace our oil and gas reserves through our acquisitions, development or exploration programs, we may also suffer a reduction in our operating cash flow and access to funds under the senior credit facilities. Under extreme circumstances, product price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.

Our cash flow from operations is driven by commodity prices and production volumes. Prices for oil and gas are driven by, among other things, seasonal influences of weather, national and international economic and political environments and, increasingly, from heightened demand for hydrocarbons from emerging nations, particularly China and India. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Cash flows from operations were primarily used to fund exploration and development of our mineral interests. Our cash flows from operations have increased each year over the last three years as has our investment in the development of our interests.

Financial Condition and Cash Flows for the Three Months Ended March 31, 2007 and 2006 and the Years Ended December 31, 2006, 2005 and 2004

The following table summarizes our sources and uses of funds for the periods noted:

	Three Months Ended March 31,						Year Ended December 31,
	2007			2006			2006			2005			2004
Cash flows provided by operations	$	2,270,736		$	1,483,404		$	12,303,864		$	9,526,277		$	5,983,247
Cash flows used in investing activities		(5,815,970	)		(19,589,193	)		(93,829,974	)		(19,404,136	)		(9,611,682	)
Cash flows provided by financing activities		4,536,701			16,748,187			79,438,356			9,771,951			5,457,300
Net increase (decrease) in cash and cash equivalents	$	991,467		$	(1,357,602	)	$	(2,087,754	)	$	(105,908	)	$	1,828,865

Operating Activities

Net cash provided by operating activities increased from $9.5 million in 2005 to $12.3 million in 2006. The increase in 2006 resulted from a combination of increased sales volumes from the acquisitions in 2006, our successful drilling activities and increased commodity prices. Average realized prices increased from $52.11 per BOE in 2005 to $56.44 per BOE in 2006. Our production volumes increased 37% to 772 MBOE in 2006 from 567 MBOE in 2005.

Net cash provided by operating activities increased from $6.0 million in 2004 to $9.5 million in 2005. The increase in 2005 resulted from a combination of increased sales volumes from the acquisitions in 2004 and 2005, our successful drilling activities and increased commodity prices. Average realized prices increased from $37.72 per BOE in 2004 to $52.11 per BOE in 2005. Our production volumes increased 51% to 567 MBOE in 2005 from 375 MBOE in 2004.

Net cash provided by operating activities increased from $1.5 million in the first quarter of 2006 to $2.3 million in first quarter of 2007. The increase in the first quarter of 2007 resulted from a combination of increased

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sales volumes from the acquisitions in 2006, which was partially offset by decreased commodity prices and a decrease in inventory, prepaid expenses and other payables. Average realized prices decreased from $56.45 per BOE in the first quarter of 2006 to $51.25 per BOE in first quarter of 2007. Our production volumes increased 53% to 248 MBOE in first quarter of 2007 from 162 MBOE in first quarter of 2006.

Investing Activities

Net cash used in investing activities increased $74.4 million from 2005 to $93.8 million in 2006. This significant change was the result of approximately $80.8 million invested in acquisitions of property and equipment, $157,000 received in proceeds from prospect sales, $34,000 in deposits and $13.2 million for exploration and development in 2006, compared with 2005, in which we used approximately $15.2 million for acquisitions of property and equipment, $3.4 million in deposits, and $4.0 million for exploration and development. In addition, we received $3.3 million in proceeds from prospect sales during 2005.

Net cash used in investing activities increased $9.8 million from 2004 to $19.4 million in 2005. This significant change resulted from our use in 2005 of approximately $15.2 million for acquisitions of property and equipment, $3.4 million in deposits, and $4.0 million for exploration and development, partially offset by our receipt of $3.3 million in proceeds from prospect sales, compared with the previous year in which we used approximately $6.7 million for acquisitions of property and equipment, $100,000 in deposits, and received $1.2 million in proceeds from prospect sales.

Net cash used in investing activities decreased $13.8 million from the first quarter of 2006 to $5.8 million in the first quarter of 2007. The decrease was the result of a decrease of approximately $17.2 million invested in acquisitions of property and equipment, which was offset by an increase of $3.7 million for development of oil & gas properties and equipment and an increase of $200,000 in proceeds related to the sale of other assets.

Financing Activities

Net cash provided by financing activities increased $69.7 million to $79.4 million for the year ended December 31, 2006. The change primarily resulted from increased borrowings of $87.5 million, partially offset by repayments of $17.2 million and payments of financing costs of $1.7 million, and equity investments from the former partners of our Founding Companies of $18.4 million, partially offset by distributions to our former partners of $7.5 million, compared with the previous year in which we had increased borrowings of $1.9 million, partially offset by repayments of $5.0 million, and equity investments from the former partners of our Founding Companies of $26.2 million, partially offset by distributions to our former partners of $13.3 million.

Net cash provided by financing activities increased $4.3 million to $9.8 million for the year ended December 31, 2005. The change was caused by primarily by increased borrowings of $1.9 million, which were partially offset by repayments of $5.0 million, and equity investments from the former partners of our Founding Companies of $26.2 million, which were partially offset by distributions to our former partners of $13.3 million.

Net cash provided by financing activities decreased $12.2 million from the first quarter of 2006 to $4.5 million in the first quarter of 2007. The change primarily resulted from decreased borrowings of $9.3 million, decreased repayments of $7.1 million and decreased capital contributions of $14.7 million, which were partially offset by decreased cash distributions and deferred offering expenses of $4.7 million.

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As of December 31, 2006 and March 31, 2007, the Founding Companies had the following senior credit facilities:

Founding Companies	Interest Rate Mechanism	As of March 31, 2007		As of December 31, 2006
PennTex Resources & PennTex Illinois (On a Combined Basis)	Prime +1%	$	17,344,536	$	14,944,536
Douglas Oil & Gas & Douglas Westmoreland (On a Combined Basis)	Prime +1%		8,991,586		8,941,586
Rex II	Prime		7,442,027		3,550,149
Rex III	Prime +1.4%		20,000,000		20,000,000
Rex IV	LIBOR +3%		38,630,634		37,580,634
Rex Operating	Fixed (Approx. 7%)		539,998		518,408
Total		$	92,948,781	$	85,535,313

As of December 31, 2006, Rex Energy IV was not in compliance with the negative covenant in its credit agreement requiring that its ratio of total debt to EBITDAX, as defined in the credit agreement, not exceed 5.5:1. Rex Energy IV obtained a waiver from its lender of this covenant for the fourth quarter of 2006. This credit facility will be repaid in full from the proceeds of this offering.

On March 30, 2007, Rex IV and KeyBank National Association, or KeyBank NA, executed the First Amendment to the Credit Agreement, which extended the maturity date to the earlier to occur of (i) the date of closing of our initial public offering and (ii) December 31, 2007. In addition, the First Amendment to the Credit Agreement provides for a change in the interest rate per annum to the LIBOR rate plus 400 basis points. The First Amendment to the Credit Agreement also made the following changes to certain negative covenants: (i) the ratio of Total Debt to EBITDAX was changed from 5.75:1.00 to 7.00:1.00 for the fiscal quarter ending June 30, 2007, 6.75:1.00 for the fiscal quarter ending September 30, 2007 and 6.50:1.00 for the fiscal quarter ending December 31, 2007; and (ii) the ratio of EBITDAX to Interest was changed from 1.75:1.00 to 1.50:1.00.

As of December 31, 2006, PennTex Resources and PennTex Illinois, as co-borrowers, were not in compliance with the negative covenant in their credit agreement requiring that their ratio of current assets to current liabilities, as defined in the credit agreement, be at least 1.1:1. The companies have received a waiver of these covenants for the fourth quarter of 2006 and the first and second quarters of 2007. This credit facility will be repaid in full from the proceeds of this offering.

As of December 31, 2006, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, were not in compliance with the negative covenant in their credit agreement which states that the co-borrowers will not permit their tangible net worth, on a combined basis, as of the end of any fiscal year to be less than such amount that is 15% less than the tangible net worth of the co-borrowers as indicated on their audited year end financial statements as of December 31, 2005; provided, however, that commencing on December 31, 2006, and at the end of each fiscal year thereafter, this amount will increase by $500,000. The companies received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarters of 2007. This credit facility will be repaid in full from the proceeds of this offering.

As of March 31, 2007, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, were not in compliance with the negative covenant in their credit agreement that states that the co-borrowers will maintain a minimum fixed coverage charge, as defined in the credit agreement, of at least 1.25. The company is in discussions with its lender to obtain a waiver and has reclassified this debt as current. The credit facility will be repaid in full from the proceeds of this offering.

As of December 31, 2006, Rex Energy III was not in compliance with the negative covenant in its credit agreement requiring that its ratio of total reserve value to total funded debt, as defined in the credit agreement, be

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at least 2.5:1. Rex Energy III obtained a waiver from its lender of this covenant for the fourth quarter of 2006 and the first quarter and the second quarter of 2007. This credit facility will be repaid in full from the proceeds of this offering.

We expect to fund our growth strategy using a combination of debt, existing cash balances, internally generated cash flows from oil and natural gas production, and the proceeds from this offering. Concurrent with the consummation of this offering, we will repay all existing credit facilities with the proceeds from the offering, and the remainder of the proceeds will be used for working capital needs. We believe that the proceeds of this offering, our available credit facilities with anticipated increases in our borrowing bases, and our operating cash flow will be sufficient to fund our operations and capital expenditures for the next 24 months. However, future cash flows are subject to a number of variables, including the level of production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures.

Proposed Credit Facility

We intend to establish a new senior credit facility. We have executed a commitment letter and term sheet with KeyBank NA, as lead arranger and administrative agent for our new senior credit facility, to finance working capital needs, and for our general corporate purposes in the ordinary course of business, including the exploration, acquisition and development of oil and gas properties. The term sheet for the credit facility provides for a $200 million facility with an initial borrowing base of $75 million. The term sheet provides for a maturity date of the fifth anniversary of the closing date of the senior credit facility, and borrowings under the credit facility will bear interest, payable on the last day of each relevant interest period in the case of the Adjusted Libor Rate option and quarterly in the case of the Prime Rate option, at a rate per annum equal to (a) the London Interbank Offered Rate for one, two, three or six months as offered by the lead bank (“Adjusted Libor Rate”) plus an applicable margin ranging from 100 to 175 basis points or (b) the higher of the lead bank’s reference rate (“Prime Rate”) and the federal funds effective rate from time to time plus 0.5% plus an applicable margin ranging from 0 to 25 basis points.

The new senior credit facility is expected to contain restrictive covenants that may limit our ability without the prior consent of the lenders to, among other things, make dividends, establish foreign subsidiaries or international operations, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, change material contracts, incur liens, enter into future oil and gas derivatives in excess of 75% of our projected proved developed producing reserves and engage in certain other transactions. The senior credit facility is also expected to require us to maintain certain ratios determined on a quarterly basis as will be further defined therein: a minimum consolidated current ratio of 1.0, a minimum ratio of EBITDAX to interest of 3.0 and a maximum ratio of total debt to EBITDAX of 4.0. There is no assurance that we will be able to secure the senior revolving credit facility on the terms set forth in such commitment letter and term sheet, if at all. The funds available to us at any time under this credit facility are limited to the amount of the borrowing base established by the banks.

Using the senior credit facility for both our short-term liquidity and long-term financing needs can cause unusual fluctuations in our reported working capital, depending on the timing of cash receipts and expenditures. On a daily basis, we use most of our available cash to pay down our outstanding balance on the senior credit facility, which is classified as a non-current liability since we currently have no required principal reductions. As we use cash to pay a non-current liability, our reported working capital decreases. Conversely, as we draw on the senior credit facility for funds to pay current liabilities (such as payables for drilling and operating costs), our reported working capital increases. Also, volatility in oil and gas prices can cause significant fluctuations in reported working capital as we record changes in the fair value of derivatives from period to period. 

Our goal is to limit our borrowings to assure that we have flexibility to expand and invest, and to avoid the problems associated with highly leveraged companies of large interest costs and possible debt reductions restricting ongoing operations.

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Capital Requirements

The oil and gas exploration and production business is capital-intensive, requiring significant investment to develop our proved and non-proved reserves and to expand our operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:

• expansion capital expenditures, such as those to acquire additional producing oil and gas fields and for undeveloped acreage positions;

• exploratory and developmental drilling capital to increase our proved reserve base or to convert our PDNP and PUD reserves to producing status; and

• maintenance or upgrade capital expenditures, which extend the useful life or upgrade the operational capabilities of existing assets.

Our total capital expenditures for 2007, excluding acquisitions, are expected to be approximately $37.9 million. The capital expenditures in 2007 are expected to include approximately $10.0 million in our Illinois Basin oil property projects, $3.5 million for our Lawrence Field ASP project, $7.3 million for our New Albany Shale drilling projects, $3.5 million in our Appalachian drilling projects and $13.6 million for our Southwest Region projects. In addition, for the five months ended May 31, 2007, we incurred capital expenditures for acquisitions of $4.4 million.

Given our objective of growth through organic expansions and selective acquisitions, we anticipate that we will continue to invest significant amounts of capital to acquire new oil and gas fields and acreage. We actively consider new opportunities for potential acquisitions, although currently we have no agreements or understandings with respect to any material acquisition, other than as described in “Summary—Recent Events.” Management believes that the net proceeds from this offering and cash flows from operations, combined with cash and cash equivalents and available borrowings under our senior credit facility, will provide us with sufficient capital resources and liquidity to manage our routine operations and fund capital expenditures that are presently projected.

Contractual Commitments

	Total		2007		2008		2009		Thereafter
Office Lease Commitments (1)	$	323,080	$	142,048	$	117,768	$	63,264	$	—
Drilling Commitments (2)		1,580,000		1,180,000		400,000		—		—
Gas Purchase Commitments (3)		10,731,000		383,250		383,250		383,250		9,581,250
Total	$	12,634,080	$	1,705,298	$	901,018	$	446,514	$	9,581,250

(1) We have a lease for our current office space in State College, Pennsylvania that expires in August 2009. Our obligation under this lease is approximately $94,896 per year. We have a lease for our current office in Midland, Texas that expires in December 2008. Our obligation under this lease is approximately $22,344 per year. We have a lease for our current office in Canonsburg (Pittsburgh), Pennsylvania that expires in August 2007. Our obligation under this lease is approximately $37,212 per year.

(2) We have a contractual commitment to drill four horizontal New Albany shale wells in our Knox AMI, where we are the operator, with minimum lateral extensions of 1,000 feet by August 30, 2007, and to take core data samples from at least two of these wells, subject to certain force majeure provisions including delays related to weather, governmental issues, acts of God, war and availability of equipment, and a contractual commitment to drill one New Albany Shale well in our Eastern Knox AMI in 2008. We currently anticipate we will be able to comply with this contractual obligation.

(3) We have a contractual commitment to purchase gas produced from a well owned by a third party in Westmoreland County, Pennsylvania which requires us to purchase up to 105,000 Mcf per year from the well at a price of 55% of the current market price, which we then resell at market price through our gathering system. To estimate the commitment amount we utilized March 31, 2007 market price and 15 years of remaining economic life.

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Off Balance-Sheet Arrangements

We do not have any off-balance sheet arrangements.

Identified Material Weaknesses of Certain Founding Companies

During the preparation of the Founding Companies’ financial statements as of and for the year ended December 31, 2006, we became aware of certain material weaknesses in our internal controls over financial reporting for certain of the Founding Companies. We have determined, and our independent registered public accounting firm has advised us, that these matters would not be material weaknesses for the combined entity but would instead constitute significant deficiencies in our internal control over financial reporting. These Founding Company material weaknesses included:

• Rex Energy II: A lack of controls over the reconciliation of the company’s asset retirement obligation was identified. In the fourth quarter of 2005, Rex Energy II planned to complete two acquisitions in December 2005; however, as a result of several delays, such acquisitions were not completed until the first quarter of 2006. During the closing of the fiscal year end the asset retirement obligations had been updated and recorded to reflect these acquisitions as if they had occurred in the fourth quarter. The effect was a reduction of the asset retirement obligation and a reduction of the corresponding proved developed oil and natural gas properties of $310,823 in 2005. We have since implemented an acquisition checklist for each item to be recorded as part of a closing for each acquisition in the appropriate period.

• PennTex Illinois: A lack of reconciliation of physical inventory counts with the general ledger inventory of the company was identified as a material weakness. Following our acquisition of the stock of PennTex Illinois in January 2005 and until September 2006, Penntex Illinois billed out tubing inventories as received to the joint interest owners of the fields operated by PennTex Illinois. In October 2006, when Rex IV, another of the Founding Companies, acquired a 49% non-operated working interest in the fields operated by PennTex Illinois, this process of inventory recording and reconciliation was corrected to record all inventory on the general ledger. The net effect was a reduction to lease operating expenses and an increase to inventory of $291,240 in 2005. We have implemented a procedure to record and maintain inventory on the general ledger.

• PennTex Resources:

• Incorrect matching of hedge settlements to the applicable period was identified as a material weakness. In March 2004, PennTex Resources entered into certain financial derivative contracts and recorded these monthly oil derivative contracts on a cash basis, thus posting the close of the contract one month forward. In December 2006, these incorrectly recorded derivative contracts were adjusted backward one month to reflect accrual based accounting. The net effect was a reduction of Realized Gains (Loss) from Financial Derivatives of $215,130 in 2005. We have now implemented a policy to match all derivative settlements to the corresponding month of production.

• A lack of recognition of certain amounts PennTex Resources owed on certain payables for drilling of non-operated wells was identified. In June 2006, Penntex Resources was contacted by a third party operator of a well in which it had participated during 2005. The third party operator advised PennTex Resources of an error in their accounting resulting in additional amounts owed on the well drilled in 2005. The net effect was an increase to wells and related equipment and an increase to payables of $341,168 in 2005. We have implemented a policy to verify amounts owed on non-operated wells prior to period end.

• A lack of control regarding revenue cutoff was identified as a material weakness. In October 2005, all non-operated properties owned by Penntex Resources were distributed to one of its limited partners as a redemption of the partner’s limited partnership interest in PennTex Resources. At the time of the redemptions, it was believed that at year end all revenues had been collected prior to the effective date of the redemption. Subsequent to year end 2005, certain revenue checks were

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received from third party operators attributable to periods prior to the effective date of the redemption. The net effect of this adjustment was an increase to oil and gas revenue of $96,180 in 2005. We have implemented a procedure to verify all revenues due from third party operators prior to period end.

Environmental

We did not have any material environmental compliance expenses during 2004 or 2005. During 2006, we incurred approximately $1.5 million in expenses associated with our legal proceedings relating to alleged H₂S emissions in the Lawrence Field. The expenses included approximately $1.3 million in facility and well improvements and $166,000 in non-reimbursed professional and legal expenses. As of March 31, 2007, we have incurred an additional $959,000 in expenses. During the remainder of 2007, we anticipate incurring an additional $590,000 in related expenses for additional property improvements, and we have accrued approximately $826,000 for legal expenses associated with our defense of the associated litigation over the next 18 months. After 2007, we anticipate we will incur approximately $50,000 in additional expenses per year for the next 5 years for monitoring and other related expenses. Please read “Business—Legal Proceedings.”

Quantitative and Qualitative Disclosure about Market Risk

Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and other related factors. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for hedging and investment purposes, not for trading purposes.

We enter into derivative contracts associated with future crude oil and natural gas prices. We do not designate our derivative instruments as cash flow hedges, and as such we classify our derivative instruments as either realized and unrealized gains, or losses, on the effective portion of the derivative to earnings when the underlying transaction occurs.

The following table summarizes our outstanding derivative contracts as of December 31, 2006:

	Crude Oil					Natural Gas
Year	Volume (Bbls)	Weighted Average Price on Put Options (Floor)		Weighted Average Price on Call Options (Ceiling)		Volume (MMBtu)	Weighted Average Price on Put Options (Floor)		Weighted Average Price on Call Options (Ceiling)
2007	637,000	$	57.89	$	63.40	720,000	$	7.76	$	13.53
2008	587,370	$	63.94	$	75.58	600,000	$	7.00	$	9.35
2009	527,637	$	62.97	$	68.85	600,000	$	7.00	$	9.28
2010	180,000	$	62.20	$	62.20	—		—		—

Subsequent to December 31, 2006, we have entered into the following additional derivative contacts as of April 17, 2007:

	Crude Oil					Natural Gas
Year	Volume (Bbls)	Weighted Average Price on Put Options (Floor)		Weighted Average Price on Call Options (Ceiling)		Volume (MMBtu)	Weighted Average Price on Put Options (Floor)		Weighted Average Price on Call Options (Ceiling)
2007	54,000	$	68.25	$	68.25	110,000	$	6.00	$	8.75
2010	180,000	$	60.00	$	77.20	—		—		—

We have reviewed the financial strength of our derivative counterparties and believe our credit risk to be minimal.

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BUSINESS

History and Development of the Company

We were incorporated on March 8, 2007 in the State of Delaware under the name Rex Energy Corporation.

Business Overview

We are an independent oil and gas company operating in the Illinois Basin, the Appalachian Basin and the southwestern region of the United States. We pursue a balanced growth strategy of exploiting our sizeable inventory of lower risk developmental drilling locations, pursuing our higher potential exploration drilling prospects and actively seeking to acquire complementary oil and natural gas properties in our core areas of operations. At December 31, 2006, our proved reserves, of which approximately 77% were proved developed, totaled approximately 14.5 million barrels of oil equivalents, or MMBOE, which were comprised of approximately 80% oil and had a reserve life index of approximately 14 years. At December 31, 2006, we operated approximately 2,150 wells, which represent approximately 95% of our total proved reserves. For the quarter ended March 31, 2007, we produced an average of 2,770 net BOE per day, comprised of approximately 81% oil and approximately 19% natural gas.

We are one of the largest oil producers in the Illinois Basin, with first quarter 2007 average net production of 2,127 net barrels of oil per day, or bopd, from approximately 1,412 gross producing wells. In addition to our production in the Illinois Basin, we have acquired, or have an option to acquire, over 270,000 gross acres in southern Indiana, which we believe are prospective for New Albany Shale exploration and development. We are also developing an enhanced oil recovery project, or EOR project, in the Lawrence Field in Lawrence County, Illinois, which we refer to as our Lawrence Field ASP Flood Project.

In our Appalachian region we own approximately 544 gross producing natural gas wells with fourth quarter 2006 average net production of 2.2 MMcf of natural gas per day, and in our Southwestern region we own approximately 118 gross producing wells in Texas and New Mexico with fourth quarter 2006 average net production of approximately 1.6 MMcfe per day, with several active drilling projects in both areas.

We are headquartered in State College, Pennsylvania, and have regional offices in Canonsburg (Pittsburgh), Pennsylvania, Midland, Texas and Bridgeport, Illinois.

Our total revenues for first quarter 2007 were $12.9 million, before the effects of oil and gas financial derivatives, and $13.1 million after the effects of realized oil and gas financial derivatives. Revenues were derived from $10.9 million in oil sales, $1.9 million in natural gas sales, $265,000 in realized losses from derivatives and $100,000 in other transportation and water disposal revenues.

In the three years ended December 31, 2006, we drilled 126 gross (61 net) wells, 95% of which are currently producing, including 68 gross (40 net) wells in the 12 months ended December 31, 2006.

The following table shows selected data concerning our production, proved reserves and undeveloped acreage in our three operating regions for the periods indicated.

Basin/Region	First Quarter 2007 Average Daily BOE	Total Proved MMBOE (As of December 31, 2006)	Percent of Total Proved MMBOE		PV-10 (As of December 31, 2006) (in millions)(1)		Total Net Undeveloped Acres (As of May 31, 2007)
Illinois Basin	2,127	10.8	74	%	$	165.5	93,033	(3)
Appalachian Basin	371	1.7	12	%		17.7	5,151
Southwestern Region	272	2.0	14	%		17.1	966
Total	2,770	14.5	100	%	$	200.3	57,411

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(1) Represents the present value, discounted at 10% per annum (PV-10), of estimated future net revenue before income tax of our estimated proved reserves. PV-10 is a non-GAAP financial measure because it excludes the effects of income taxes and asset retirement obligations. PV-10 should not be considered as an alternative to the pro forma standardized measure of discounted future net cash flows as defined under GAAP. At December 31, 2006, our pro forma standardized measure was $132.1 million. For an explanation of why we show PV-10 and a reconciliation of PV-10 to the pro forma standardized measure of discounted future net cash flows, please read “Selected Historical Financial and Operating Data—Non-GAAP Financial Measures.” Please also read “Risk Factors—Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.”

(2) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes proved reserves.

(3) Includes approximately 70,000 gross (20,900 net) acres in Indiana under option for $25.00 per net acre.

In addition to our proved reserves, we have assembled an extensive inventory of non-proved projects. We believe that our projected cash flows from our proved reserve base and availability under our proposed $75 million senior credit facility will enable us to fund a high percentage of our planned capital expenditures to develop our non-proved asset base with internally generated funds. Please read “—Capital Expenditures.”

Our Competitive Strengths

We believe our historical success is, and future performance will be, directly related to the following combination of strengths that we believe will enable us to implement our strategy:

Significant Production Growth Opportunities: We have several projects and properties that we believe are capable of resulting in significant proved reserves and production growth. These include:

• Our Lawrence Field ASP Flood Project in Illinois (please read “—Our Active Projects—Illinois Basin Projects—The Lawrence Field ASP Flood Project”);

• Our large New Albany Shale acreage position of over 270,000 gross acres in southern Indiana (please read “—Our Active Projects—Illinois Basin Projects—The Illinois Basin New Albany Shale Project”);

• Our natural gas drilling opportunities in the Appalachian Basin on over 50,000 gross acres in Pennsylvania;

• Our oil drilling opportunities in the Illinois Basin, including 210 proved undeveloped drilling locations in Illinois and Indiana; and

• Our oil and gas development projects in the Permian Basin.

Market Leader in the Illinois Basin: We are one of the largest oil producers and a market leader in the Illinois Basin, which enables us to realize a current premium over the basin posted prices on our oil production and a competitive cost structure due to economies of scale, and provides us with a unique local knowledge of the basin. We believe these advantages will also enhance our ability to continue to make strategic acquisitions in the basin.

Experienced Management Team with a Proven Track Record: We have significant technical and management experience in our core operating areas. Our technical team of geologists and engineers averages over 20 years of experience, primarily in the Illinois, Appalachian and Permian Basins. We believe the experience and capabilities of our management team have enabled us to build a high quality asset base of proved reserves and growth projects, both organically and through selective acquisitions.

Financial Flexibility: We plan to maintain a conservative financial position. We expect to use a portion of the proceeds from this offering to retire all senior debt facilities of the Founding Companies, which will provide

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us with an initial debt-free balance sheet and enable us to utilize our operating cash flows to pursue our planned growth through our exploration and development activities. In addition, we have received a commitment from Keybank, NA to establish a new senior credit facility with an initial borrowing capacity of $75 million for working capital purposes, including new acquisitions. Our oil and gas financial derivative activities will enable us to maintain greater stability in our operating cash flows while we continue to develop our properties.

Incentivized Management Ownership: After giving effect to the Reorganization Transactions and the offering described in this prospectus, our directors and officers will beneficially own approximately 45.7% of our outstanding common stock. Therefore, the interests of our directors and executive officers are closely aligned with those of our stockholders.

Business Strategy

Our strategy is to increase stockholder value by profitably increasing our reserves, production, cash flow and earnings. The following are key elements of our strategy:

• Employ Technological Expertise: We intend to utilize and expand the technological expertise that has enabled us to achieve a drilling completion rate of approximately 95% during the last three years and has helped us improve operations and enhance field recoveries. We intend to apply this expertise to our proved reserve base and our development projects.

• Develop Our Existing Properties: We will continue to focus on developing our asset base in each of our operating basins including:

• Our Lawrence Field ASP Flood Project in Illinois;

• Our New Albany Shale resource play with over 270,000 (88,000 net) gross acres; and

• Our inventory of over 500 proved undeveloped locations and proved developed non-producing wells.

• Pursue Strategic Acquisitions and Joint Ventures: We expect to continue to acquire and lease additional natural gas and oil properties in our core areas of operation. We believe that our strong history of acquisitions, leading position in the Illinois Basin and technical expertise position us well to attract industry joint venture partners and to continue pursuing strategic acquisitions.

• Focus on Operations: We expect to focus our future acquisition and leasing activities on properties where we have a significant working interest and can operate the property to control and implement the planned exploration and development activity.

• Reduce Per Unit Operating Costs Through Economies of Scale and Efficient Operations: As we continue to increase our oil and natural gas production and develop our existing properties, we believe that our per unit production costs will benefit from increased production in lower cost operations and through better utilization of our existing infrastructure over a larger number of wells.

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Areas of Operations

Illinois Basin Properties

We are currently one of the leading oil producers in the Illinois Basin with operations throughout southern Illinois and Indiana. The following table shows our proved properties in the Illinois Basin:

State/County	Proved Developed Producing Reserves (MBbls)	Proved Developed Non-Producing Reserves (MBbls)	Proved Undeveloped (MBbls)	Total Proved Reserves (MBbls)
Illinois/Clay	39	—	—	39
Illinois/Fayette	245	1	—	246
Illinois/Lawrence	5,200	1,112	1,427	7,740
Illinois/Gallatin	222	—	—	222
Indiana/Davies	407	—	43	451
Indiana/Gibson	118	21	99	238
Indiana/Posey	840	100	293	1,233
Indiana/Sullivan	241	—	—	241
Indiana/Vigo	245	—	112	357
Total	7,558	1,235	1,974	10,767

Significant Projects in the Illinois Basin

Lawrence Field ASP Flood Project. The Lawrence Field in Lawrence County, Illinois, is believed to have produced more than 400 million barrels of oil from 23 separate horizons since its discovery in 1906. We currently own and operate 21.2 square miles (approximately 13,500 net acres) of the Lawrence Field and our properties account for approximately 85% of the current total gross production from the field. The Cypress (Mississippian) and the Bridgeport (Pennsylvanian) sandstones are the major producing horizons in the field. To date, approximately 40% of the estimated one billion barrels of original oil in place has been produced.

We are implementing an alkali surfactant polymer, or ASP, flood project in the Cypress and Bridgeport Sandstone reservoirs of our Lawrence Field acreage, which we refer to as our Lawrence Field ASP Flood Project. The Lawrence Field ASP Flood Project is one of our largest projects. The ASP flood is considered an EOR project, which refers to recovery of oil that is not producible by primary or secondary recovery methods.

Primary recovery refers to the first oil produced in a new field solely from natural reservoir pressure. Typically, primary recovery methods in oil fields can recover 10% to 20% of the original oil in place. Secondary recovery methods are used when there is insufficient underground pressure to move the remaining oil to the wellbore. The most common technique, waterflooding, utilizes injector wells to introduce volumes of water under pressure into the hydrocarbon-bearing zone. As water flows through the formation toward the producing wellbore, it sweeps some of the oil it encounters along with it. This secondary recovery process was initiated in the Lawrence Field during the 1950s and is believed to have increased total recovery to approximately 40% of the original oil in place to date. When secondary recovery reaches a point when the waterflood no longer is efficiently sweeping the remaining oil in the reservoir, an EOR project may be implemented to recover a portion of the remaining oil in place. The chart below shows typical primary and secondary recovery of original oil in place from the Bridgeport and Cypress formations in the Lawrence Field as estimated by the U.S. Department of Energy, with tertiary recovery based on EOR project results in the Lawrence Field.

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In the 1960s, 1970s and 1980s, a number of EOR projects using surfactant polymer floods were implemented in several fields in the Illinois Basin by Marathon Oil Corp., Texaco and Exxon in an attempt to recover a portion of the large percentage of the original oil in place that was being bypassed by the secondary recovery waterflood. These test projects reportedly were able to recover incremental oil reserves of 15% to 30% of the original oil in place.

In 1982, Marathon began a surfactant polymer flood project in the Lawrence Field on the Robins Lease, a 25-acre lease in the Lawrence Field within one mile of the site of one of our pilot test locations. This project was initiated at a time when the price per barrel of oil was below $15 per barrel and the technology of combining alkali and surfactant with polymer, which significantly reduces costs of recovery compared with the previous surfactant polymer floods, had not yet been fully developed. Despite the high costs of the surfactant polymer flooding employed by Marathon and the low oil prices, the project produced an estimated 450,000 incremental barrels, or an estimated 21% the of original oil in place. The graph below shows the production response of the Robins lease to the surfactant polymer flood. While we believe the results of this project are pertinent, there can be no assurance that our ASP flood project, which utilizes technology that was not developed at the time of the Robins Lease flood, will achieve similar results.

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Robins Lease Surfactant-Polymer Flood Production

ASP technology, which uses similar mechanisms to mobilize bypassed residual oil as these previous surfactant polymer floods but at significantly lower costs, has been applied in several fields around the world resulting in significant incremental recoveries of the original oil in place. Chemicals used in the ASP flood are an alkali (NaOH or Na2CO3), a surfactant and a polymer. The alkali (1% to 2%) and surfactant (0.1% to 0.4%) combination washes residual oil from the reservoir mainly by reducing interfacial tension between the oil and the water. The polymer (800 to 1400 parts per million) is added to improve sweep displacement efficiency. ASP technology achieves its incremental recovery by reducing capillary forces that trap oil, improving aerial and vertical sweep efficiency and reducing mobility ratio.

Our Lawrence Field ASP Flood Project will utilize ASP technology to flood our Lawrence Field wells. The goal of our Lawrence Field ASP Flood Project is to duplicate the oil recovery performance of the surfactant polymer floods conducted in the field in the 1980s, but at a significantly lower cost. We expect this cost reduction to be accomplished by utilizing newer technologies to optimize the synergistic performance of the three chemicals used, and by using alkali in the formula, which would allow us to use a significantly lower concentration of the more costly surfactant.

In 2000, PennTex Illinois, then known as Plains Illinois, Inc., and the U.S. Department of Energy conducted a study on the potential of an ASP project in the Lawrence Field with consulting services provided by Surtek, Inc., an independent engineering firm specializing in the design and implementation of chemical oil recovery systems. Based on modeling of the reservoir characteristics and laboratory tests with cores taken in the Lawrence Field, the evaluation found oil recovery in the field could be increased significantly by installing an ASP flood. Similar EOR techniques have been successfully demonstrated in fields around the world to recover an additional 15% to 30% of the original oil in place. However, there can be no assurance that our Lawrence Field ASP Flood Project will achieve similar results.

In 2006, we engaged Surtek to review and update the evaluation on the application of the ASP process to the Lawrence Field. This evaluation, based on laboratory results, recommended two pilot areas to evaluate the ASP process in the Bridgeport and Cypress sandstones. The ASP pilot test locations are positioned in areas that we believe are representative of variabilities that can be expected in a large-scale commercial application of this

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technology in these reservoirs. Based on Surtek’s recommendations, we drilled and cored the central producing well in each of the two proposed pilot test areas. These cores have been sent to Surtek for ASP chemical system design. We have also begun designing the injection plant to be used in the pilot tests. We plan to initiate injection of the ASP chemicals on the two one-acre pilots recommended by Surtek in 2007. If either of these two pilots is successful, we plan to implement a broad ASP flood program within the 13,500 net acres of the field that we currently own and operate, commencing in 2008. While we are encouraged by initial laboratory results, our EOR project in the Lawrence Field is not a proved project nor are any of the potential reserves from this project considered proved at this time.

New Albany Shale. As of May 31, 2007, we had acquired, or had an option to acquire, over 270,000 gross (88,000 net) acres in southern Indiana that we believe to be prospective for New Albany Shale development. The New Albany Shale is predominantly an organic-rich black shale that is present in the subsurface throughout the Illinois Basin. Where the stratigraphy is known, the gas reservoirs are observed to be in the organic-rich black shales of the Grassy Creek (Shale), Clegg Creek, and Blocher (Shale) Members. Natural fractures are believed to provide the effective reservoirs permeability in these zones and gas is stored both as free gas in fractures and as adsorbed gas on kerogen and clay surfaces. Although limited gas production from vertical wells in the New Albany Shale has occurred for many years, interest in the potential of the New Albany Shale has recently increased due to the application of horizontal drilling techniques which can intersect numerous vertical fractures, significantly increasing the amount of reservoir contacted by each wellbore.

While New Albany Shale horizontal drilling is still in its exploratory stage, it has attracted the attention of several large oil and gas companies that are currently drilling in southern Indiana and northern Kentucky, including Chesapeake Energy Corporation (NYSE: CHK), Quicksilver Resources Inc. (NYSE: KWK), Aurora Oil & Gas Corporation (AMEX: AOG), Samson Investment Company, Noble Energy, Inc. (NYSE: NBL) and El Paso Corporation (NYSE:EP). Although recent New Albany Shale drilling in Indiana by other operators has been conducted on 160 acre spacing, we believe as the play develops the average well spacing will be 320 acres.

Our New Albany Shale acreage is located in four main project areas in addition to our acreage held by production in Southern Indiana:

• We own a 40% working interest (33% average net revenue interest) in approximately 18,000 gross acres eastern Knox County, Indiana, which we refer to as the Eastern Knox AMI. We are the operator within the Eastern Knox AMI. The operating agreement covering this area gives owners the right to propose drilling units of 640 acres and provides for a penalty to non-consenting working interest owners that allocates all revenue received from production on the unit until the consenting parties have received back 200% of their investment in the unit. In the event we, as the operator of the area, elect not to participate in the proposed drilling unit, the consenting parties may designate a new operator for such unit.

• We own a 26.8% working interest (22.6% average net revenue interest) in approximately 40,800 gross acres with Aurora Oil & Gas Corporation, Baseline Oil & Gas Corp. and Source Rock Resources, Inc. in Knox County, Indiana which we refer to as the Western Knox AMI. We are the operator within the Western Knox AMI. The operating agreement covering this area gives owners the right to propose drilling units of 640 acres and provides for a penalty to non-consenting working interest owners that allocates all revenue received from production on the unit until the consenting parties have received back 200% of their investment in the unit. In the event we, as the operator of the area, elect not to participate in the proposed drilling unit, the consenting parties may designate a new operator for such unit.

• We own a 29.1% working interest (24.4% average net revenue interest) in approximately 113,265 gross acres with Aurora Oil & Gas Corporation and Baseline Oil & Gas Corp. in Greene, Owen, Sullivan and Clay Counties, Indiana, which we refer to as the Wabash AMI. In addition, we own an option to acquire a 29.8% working interest (25.2% average net revenue interest) in approximately 70,000 gross acres in Washington, Lawrence, Jackson and Orange Counties, Indiana from Aurora Oil & Gas Corporation for $25.00 per net acre until August 1, 2007. Aurora Oil & Gas Corporation is the operator

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within the Wabash AMI. The operating agreement covering this area gives owners the right to propose drilling units of 2,560 acres and provides for a penalty to non-consenting working interest owners that allocates all revenue received from production on the unit until the consenting parties have received back 200% of their investment in the unit. In the event Aurora Oil & Gas Corporation, as the operator of the area, elects not to participate in the proposed drilling unit, then the consenting party with the highest working interest is designated as the operator for such unit.

• We own a 10.1% working interest (8.3% average net revenue interest) in 8,735 gross acres in Greene County, Indiana, with Aurora Oil & Gas Corporation, Baseline Oil & Gas Corp. and El Paso Corporation. El Paso Corporation is the operator of this area of mutual interest.

Since February 2006, we have participated in 11 gross New Albany Shale wells, four of which we operate, in Greene County and Knox County, Indiana, which are currently being tested to determine whether they will be economical to complete and produce and to design stimulation procedures, if required. We plan to drill 10 gross wells in the Western Knox AMI in 2007, and we anticipate that Aurora Oil & Gas Corporation will drill 10 wells in the Wabash AMI during 2007.

Appalachian Basin Properties

We own approximately 544 gross producing natural gas wells in the Appalachian Basin, predominantly in Pennsylvania. These wells are characterized as shallow, predominantly drilled on 40 acre spacing at depths less than 5,000 feet, natural gas wells which have historically been long-life shallow decline reserves. In addition to our producing wells in the basin, we own 36 proved undeveloped drilling locations with total reserves of 3.5 Bcf, and six wells with proved developed non-producing reserves totaling 855 MMcf. At December 31, 2006, we owned approximately 53,000 gross (38,000 net) acres in the Appalachian Basin, of which 15,000 gross (5,100 net) acres were undeveloped.

State/County	Proved Developed Producing Reserves (Bcf)	Proved Developed Non-Producing Reserves (Bcf)	Proved Undeveloped Reserves (Bcf)	Total Reserves (Bcf)
PA/Warren	0.9	—	—	0.9
PA/Westmoreland	3.0	0.6	3.4	7.0
PA/NY/VA/WV/Other	2.1	0.3	0.1	2.5
Total	6.1	0.9	3.5	10.5

Significant Projects in the Appalachian Basin

Fayette County. In Fayette County, Pennsylvania, we own approximately 22,000 gross (7,330 net) acres, of which approximately 12,900 gross (3,000 net) acres are undeveloped. As of December 31, 2006, we owned 122 producing gas wells on our Fayette County properties with total proved reserves of 192 MBOE. Great Lakes Energy, a wholly owned subsidiary of Range Resources Corporation, is the operator on approximately 5,000 gross undeveloped acres in which we own an average working interest of 16%. This area has historically been drilled on 40 acre spacing. During 2006, we participated in the drilling and completion of 24 wells and one dry hole (a 96% success rate) in this project area, at a cost of approximately $222,000 per well.

Westmoreland County. In Westmoreland County, Pennsylvania, we own a 100% working interest in approximately 73 natural gas wells and 2,100 undeveloped acres with total proved reserves of 1,180 MBOE. We believe that we can drill an additional 125 to 150 wells in the field on our current acreage. Since acquiring the field in 2004, we have drilled and completed 20 wells, with a 100% success rate. These wells target the Bradford Sands at a depth of approximately 4,000 feet at an average cost of approximately $192,000 per well.

Marcellus Shale Potential. Our properties in Western Pennsylvania are located in areas where active exploration for the Marcellus Shale, by companies such as Range Resources Corporation (NYSE:RRC) and Atlas

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Energy Resources, LLC (NYSE: ATN), is currently occurring with encouraging results. The Marcellus Shale is a black, organic rich shale formation located at depths between 7,000 and 8,500 feet and ranges in thickness from 100 to 150 feet in Western Pennsylvania. Our acreage in Western Pennsylvania totals 53,000 gross acres (38,600 net acres), 87% of which is currently held by production. As the vast majority of our acreage in Western Pennsylvania is held by production, we expect to test several areas of our acreage after this emerging play has been further tested and refined in our area by other operators.

Southwestern Region Properties

Our operations in our Southwestern region include several producing oil and gas fields in Lea & Eddy Counties, New Mexico; Terrell County, Texas and other producing regions of western Texas. At December 31, 2006, we operated 46 wells, and owned interests in another 61 wells, in west Texas and southeast New Mexico. The following table shows our proved properties in our Southwestern region:

State/County	Proved Developed Producing Reserves (Bcfe)	Proved Developed Non-Producing Reserves (Bcfe)	Proved Undeveloped Reserves (Bcfe)	Total Reserves (Bcfe)
NM/Eddy	1.4	0.7	1.8	3.9
NM/Lea	1.8	0.3	1.3	3.4
TX/Midland	1.2	—	0.9	2.1
TX/Terrell	0.9	—	—	0.9
TX & NM/Other	1.1	—	0.3	1.4
Total	6.4	1.0	4.3	11.7

Significant Projects in the Southwestern Region

Allison Field. We own a 50% working interest in and operate the Allison Field in Terrell County, Texas. As of December 31, 2006, the field was comprised of 15 producing wells with 154 MBOE of proved reserves. Our leasehold covers 4,480 gross acres in the field. We have identified several recompletion and workover opportunities in the field, as well as drilling potential in both the Canyon and Leonard sands.

Azalea Field. We own a 95% working interest in and operate the Azalea Field in Midland County, Texas. As of December 31, 2006, our properties in the field included 16 gross wells with 345 MBOE of proved reserves. Our leasehold covers approximately 1,900 gross acres in Midland County, Texas. We have identified several development opportunities, including the perforation of the Grayburg zone which we believe, based on well log analysis, can be productive in several of the wells. We plan to install a waterflood of the Grayburg reservoir in the field in 2008.

East Carlsbad Field. We own an average 33% working interest in the East Carlsbad Field in Lea and Eddy Counties, New Mexico. As of December 31, 2006, our properties in the field included 13 gross producing wells, 10 of which we operate, with 522 MBOE of proved reserves. Our leasehold covers approximately 2,400 gross acres. We have identified several potential improvements in the field, including the workover of several wells, testing the potential of increased density drilling of the Cisco/Wolfcamp formations and recompleting certain wells to the Atoka formation. If the Atoka recompletion is successful we believe we could drill several offset wells on our acreage.

Pecan Station Prospect. We own a 100% working interest in 480 acres in the Pecan Station Field in Tom Green County, Texas, which we refer to as the Pecan Station prospect. The Pecan Station Field’s discovery well was drilled in October of 1953 and tested at 4,000—5,000 Mcfd of natural gas in the Strawn formation, but was never produced due to a lack of natural gas gathering lines in the area. Since that time, four additional wells have been drill stem tested in the Strawn formation and flowed gas. We plan to drill a new well on the acreage to test the Strawn Lime in 2007, and pending the success of the initial well, we intend to drill an additional three to four wells on our acreage in the prospect area in 2007 and 2008.

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Bison Prospect. We own a 100% working interest in 240 acres in Garza County, Texas, which we refer to as the Bison prospect. The Bison prospect is based upon re-entering a well on the acreage that was drilled in 1981 to the Ellenburger formation. We intend to commence this re-entry in 2007 to test three prospective objectives: the Spraberry formation at 5,100 feet and the Strawn Lime ‘A’ and ‘B’ formations found at 7,450 feet and 7,500 feet, respectively. Based on geological mapping, we believe that the Spraberry and Strawn formations are present and have been shown to be productive in the project area. If this re-entry results in successful commercial production from either of the Spraberry or Strawn formations, we intend to drill an additional six to eight wells on our acreage in 2007 and 2008.

The New Batson Field. We own a 90% working interest before return of our invested capital and a 75% working interest after the return of our capital in the Batson Field in Hardin County, Texas. We are the operator of the property. We acquired the field in 2007 from the Central Utilities Production Corp.’s bankruptcy estate. When the seller of the field filed for bankruptcy in August 2003, most of the wells on the property were shut in due to the lack of a salt water disposal well on the property, and subsequently most of the surface equipment was removed from the wells. As of December 31, 2006, there were 31 shut-in wells and three producing wells on the property with total production of six gross barrels of oil per day. We intend to convert one of the shut-in wells to a salt water disposal well, which has already been permitted, workover the three producing wells and return 29 of the shut-in wells to production in 2007. Additionally, we intend to test the Miocene sand at 1,600 feet in depth, which has been completed in the wells offsetting one of the leases on our property, with initial production rates in the range of 150-300 Mcfd.

Dare I Hope & Cook Fields. We own an 84% working interest in the Dare I Hope and Cook Fields in Concho County, Texas which we acquired in April 2007. We are now the operator of the property. Prior to the acquisition, Douglas Oil & Gas, one of the Founding Companies, owned a 32% non-operated working interest in the Cook Field. As of December 31, 2006, there were 10 producing oil wells, 8 water injection wells, 3 water supply wells and 8 shut-in wells on the fields with total production of 50 gross barrels of oil per day. The fields have produced approximately 1.4 million barrels to date since their discovery in 1996. We believe the fields have historically underperformed due to poor sweep efficiency from the current waterflood design, the lack of a chemical treatment program and ineffective operations. We intend to redesign the current waterflood pattern, implement a new chemical program in the field to reduce scale buildup and test the use of polymer gels to increase sweep efficiency in the fields.

Acquisition History

Since 2004, we have completed 17 significant acquisitions in our core operating areas. Three of these consisted of acreage acquisitions in the Illinois Basin associated with our New Albany Shale project for approximately $6.6 million. Fourteen of these consisted of producing properties, which as of May 31, 2007 have added 13.2 MMBOE to our proved reserves, for approximately $92.3 million in acquisition costs, or an average cost per proved BOE of $6.99.

The following table summarizes our producing property acquisitions since 2004:

	Producing Property Acquisitions
Year	Approx. Purchase Price (in millions)		Proved Reserves (MMBOE)	Average Cost per Proved BOE
2004	$	7.0	3.1	$	2.25
2005		17.6	3.6		4.87
2006		65.7	6.4		10.33
2007		2.0	0.1		20.00
	$	92.3	13.2	$	6.99

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Capital Expenditures

We have established a capital budget, excluding acquisitions, of approximately $37.9 million for 2007 and approximately $32.9 million for 2008. These budgets are based upon expected volumes produced and commodity prices. We intend to use a substantial portion of our proceeds, net of underwriting discounts and fees and expenses, from the offering to retire all of our debt and for working capital. In addition, we have received a commitment from Keybank, NA to establish a new senior credit facility with an initial borrowing capacity of $75 million for working capital and general corporate purposes, including new acquisitions. We believe that our projected cash flows from our proved reserve base and availability under our new senior credit facility will enable us to fund our planned capital expenditures in 2007 and 2008.

The following table summarizes information regarding our historical 2006 and our estimated 2007 and 2008 capital expenditures. The estimated 2007 capital expenditures shown are preliminary full year estimates, including approximately $13.6 million spent from January 1, 2007 through May 31, 2007, which includes approximately $4.4 million in acquisitions. The estimated capital expenditures are subject to change depending upon a number of factors, including availability of capital, drilling results, oil and gas prices, costs of drilling and completion and availability of drilling rigs, equipment and labor. The historical 2006 capital expenditures below include capital expenditures for acquisitions and leasing. In addition, the estimates for 2007 include $2.0 million for acquisitions and $2.4 million for leasing, reflecting acquisitions and leases made or entered into prior to May 31, 2007. We do not attempt to budget for future investments in acquisitions or leasing.

	Year Ending December 31,
	2006 (historical)		2007 (estimated)		2008 (estimated)
	(in millions)
Capital expenditures
Illinois Basin Conventional Oil Operations	$	7.6	$	10.0	$	5.1
Illinois Basin ASP Flood Project		0.1		3.5		0.7
New Albany Shale Project		2.5		7.3		17.9
Appalachian Basin Operations		2.3		3.5		3.3
Southwestern Region Operations		1.1		13.6		5.9
Acquisitions of proved oil and gas properties		67.7		2.0		—
Acquisition and leasing of undeveloped properties		14.3		2.4		—
Total capital expenditures	$	95.6	$	42.3	$	32.9

Exploration and Development Costs

The prices received for domestic production of oil and natural gas have increased significantly during the past several years and may continue to increase in response to global political issues and domestic shortages. These price increases have resulted in increased demand for the equipment and services that we need to drill, complete and operate wells. As a result of this increased demand for oil field services, shortages have developed, and we have seen an escalation in drilling rig rates, field service costs, material prices and all costs associated with drilling, completing and operating wells. If oil and natural gas prices remain high relative to historical levels, we anticipate that the recent trends toward increasing costs and equipment shortages will continue.

Our Proved Reserves

Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm, evaluated our reserves on a consolidated basis as of December 31, 2006. A complete copy of its evaluation is attached to this prospectus as Appendix A. All of our reserves are located within the continental United States. Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of additional exploration and development, prices of oil and natural gas and other factors. Please read “Risk Factors—Our estimated reserves are

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based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.” You should also read the notes following the table below and our financial statements for the year ended December 31, 2006 included elsewhere in this prospectus in conjunction with the following reserve estimates. The following table shows our summary proved reserves and our PV-10 value as of December 31, 2006.

	As of December 31, 2006
Estimated Proved Reserves(1)
Gas (Bcf)		17.2
Oil (MMBbls)		11.6
Total proved reserves (MMBOE)(2)		14.5
Total proved developed producing reserves (MMBOE)		9.6
PV-10 Value (millions)(3)
Proved developed producing reserves	$	143.9
Proved developed non-producing reserves		24.1
Proved undeveloped reserves		32.3
Total PV-10 value	$	200.3
Pro Forma Standardized Measure (millions)(4)	$	132.1

(1) The estimates of reserves in the table above conform to the guidelines of the SEC. Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our financial derivative activities. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The estimated present value of proved reserves does not give effect to indirect expenses such as general and administrative expenses, debt service and future income tax expense, asset retirement obligations or to depletion, depreciation and amortization. The reserve information shown is estimated. The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and present value are based on various assumptions, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

(2) We converted natural gas to barrels of oil equivalent at a ratio of one barrel to six Mcf.

(3) Represents the present value, discounted at 10% per annum (PV-10), of estimated future net revenue before income tax of our estimated proved reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on economic conditions prevailing at December 31, 2006. The estimated future production is priced at December 31, 2006, without escalation, using $57.75 per bbl and $5.635 per MMBtu and adjusted by lease for transportation fees and regional price differentials. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. For an explanation of why we show PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flow, please read “Selected Historical Financial and Operating Data—Non-GAAP Financial Measures.” Please also read “Risk Factors—Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.”

(4) Because each of the Founding Companies was a flow-through entity for state and federal tax purposes, our historical standardized measure does not deduct state or federal taxes. This differs from our pro forma standardized measure, which deducts state and federal taxes.

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Acreage and Productive Wells Summary

The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases and our gross and net productive oil and gas wells as of December 31, 2006:

	Undeveloped Acreage(1)		Developed Acreage(2)		Total Acreage		Producing Gas Wells			Producing Oil Wells
	Gross	Net	Gross	Net	Gross	Net	Gross		Net	Gross	Net
Appalachian Basin
Pennsylvania	15,060	5,151	38,091	33,534	53,150	38,685	443	(3)	182	0	0
Illinois Basin
Illinois	11,923	4,000	28,349	18,285	40,272	22,285	0		0	1,199	1,194
Indiana	272,761	88,557	11,924	11,482	284,685	100,039	0		0	219	213
Kentucky	1,244	474	710	17	1,954	491	0		0	0	0
Total Illinois Basin	285,928	93,031	40,982	29,784	326,910	122,815	0		0	1,418	1,407
Permian Basin
Texas	720	640	8,331	5,746	9,051	6,386	21		7	32	30
New Mexico	437	326	4,320	1,920	4,757	2,246	43		7	22	5
Total Permian Basin	1,157	966	12,651	7,666	13,808	8,632	64		14	54	35
Total	302,144	99,148	91,724	70,984	393,869	170,132	507		196	1,472	1,442

(1) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes proved reserves.

(2) Developed acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production.

(3) In addition, we own royalty interests in approximately 71 natural gas wells in the Appalachian Basin.

Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing lease is renewed or we have obtained production from the acreage subject to the lease prior to the end of the primary term, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net acres of undeveloped land subject to leases summarized in the preceding table that will expire during the periods indicated:

	Expiring Acreage
Year Ending December 31,	Gross	Net
2007	4,839	3,216
2008	6,028	3,515
2009	59,697	19,059
2010	49,742	15,149
Thereafter	181,838	58,209
Total	302,144	99,148

Sale of Production

In the Illinois Basin, we store the oil produced at the well site tanks and sell our oil to Countrymark Cooperative, LLP, a local refinery, currently at a premium to the basin posted prices. This premium is provided to us due to our significant size in the basin relative to other local producers. The oil is purchased at our tank facilities from the refiner and trucked to its refinery facilities. The revenue we derived from our sales to Countrymark Cooperative, LLP for the year ended December 31, 2006 constituted approximately 75% of our total revenue for such period. As such, we are currently significantly dependent on the creditworthiness of Countrymark Cooperative, LLP. Please read “Risk Factors—We depend on a relatively small number of customers for a substantial portion of our revenue. The inability of one or more of our customers to meet their

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obligations or the loss of our business with Countrymark Cooperative, LLP, in particular, may adversely affect our financial results.” We are currently in the process of constructing our own offload facility at a nearby crude oil pipeline operated by Marathon Oil Corp. that will enable us to diversify our purchasers in the future should the need arise. In the Appalachian Basin, our natural gas producing properties are located near existing pipeline systems and processing infrastructure. The majority of our production is transported over our own gathering lines to local distribution companies. In the Appalachian Basin, due to its proximity to large east coast cities, we generally receive a premium over market prices for our gas production of approximately $0.25-$0.50 per Mcf. In the Permian Basin we market our oil and gas production to various oil purchasers and pipeline systems at facilities located near our existing gathering systems or well site tanks.

Prices for oil and natural gas fluctuate fairly widely based on supply and demand. Supply and demand are influenced by a number of factors, including weather, foreign policy and industry practices. For example, demand for natural gas has increased in recent years due to a trend in the power plant industry to use natural gas as a fuel source instead of oil and coal because natural gas is a cleaner burning fuel, and demand for oil has increased due to increased industrialization in many parts of the world. Nonetheless, in light of historical fluctuations in prices, there can be no assurance at what price we will be able to sell our oil and natural gas. Prices may be low when our wells are most productive, thereby reducing overall returns.

Product Prices and Production

Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. Commodity prices are beyond our control and are difficult to predict. The oil and natural gas volumes that we produced and the average prices that we received for that production for the three months ended March 31, 2007 and 2006, and the years ended December 31, 2006, 2005 and 2004, and the three months ended March 31, 2007 and 2006 are set forth below. These figures do not take into account our financial derivative activities during this period.

	Three Months Ended March 31,		Year Ended December 31,
	2007	2006	2006	2005	2004
Volume:
Gas (MMcf)	283	294	1,109	1,126	1,067
Oil (MBbls)	201	113	587	379	197
BOE (MMBOE)	249	162	772	566	375
Average Price:
Gas ($/Mcf)	6.63	8.68	7.04	8.15	5.93
Oil ($/Bls)	53.98	58.33	60.92	53.71	39.67
BOE ($/BOE)	51.29	56.45	56.44	52.11	37.72

Generally, the demand for and the price of natural gas increases during the colder winter months and decreases during the warmer summer months. Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Crude oil and the demand for heating oil are also impacted by seasonal factors, with generally higher prices in the winter. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations.

Oil and Natural Gas Derivatives

We enter into derivative contracts associated with future crude oil and natural gas prices. We do not designate our derivative instruments as cash flow hedges, and as such we classify our derivative instruments as either realized and unrealized gains, or losses, on the effective portion of the derivative to earnings when the underlying transaction occurs.

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The following table summarizes our outstanding derivative contracts as of December 31, 2006:

	Crude Oil					Natural Gas
Year	Volume (Bbls)	Weighted Average Price on Put Options (Floor)		Weighted Average Price on Call Options (Ceiling)		Volume (MMBtu)	Weighted Average Price on Put Options (Floor)		Weighted Average Price on Call Options (Ceiling)
2007	637,000	$	57.89	$	63.40	720,000	$	7.76	$	13.53
2008	587,370	$	63.94	$	75.58	600,000	$	7.00	$	9.35
2009	527,637	$	62.97	$	68.85	600,000	$	7.00	$	9.28
2010	180,000	$	62.20	$	62.20	—		—		—

Subsequent to December 31, 2006, we have entered into the following additional derivative contacts as of April 17, 2007:

	Crude Oil					Natural Gas
Year	Volume (Bbls)	Weighted Average Price on Put Options (Floor)		Weighted Average Price on Call Options (Ceiling)		Volume (MMBtu)	Weighted Average Price on Put Options (Floor)		Weighted Average Price on Call Options (Ceiling)
2007	54,000	$	68.25	$	68.25	110,000	$	6.00	$	8.75
2010	180,000	$	60.00	$	77.20	—		—		—

We have reviewed the financial strength of our derivative counterparties and believe our credit risk to be minimal.

Drilling Activity

All of our drilling activities are conducted on a contract basis by independent drilling contractors. We own seven workover rigs which are utilized in our Illinois Basin operations. We do not own any drilling equipment. The following table sets forth the number and type of wells that we drilled during the years ended December 31, 2004, 2005 and 2006.

	Year Ended December 31,
	2004		2005		2006		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Development:
Illinois Basin	—	—	3.0	1.5	24.0	23.9	27.0	25.4
Appalachian Basin	24.0	9.8	30.0	9.3	31.0	11.4	85.0	30.6
Southwestern Region	—	—	—	—	2.0	0.3	2.0	1.3
Non-Productive	1.0	0.9	1.0	0.1	3.0	2.1	5.0	3.2
Total	25.0	10.7	34.0	10.9	60.0	37.7	119.0	60.5
Exploratory:
Illinois Basin	—	—	—	—	6.0	2.2	6.0	2.2
Appalachian Basin	—	—	—	—	—	—	—	—
Southwestern Region	—	—	—	—	—	—	—	—
Non-Productive	—	—	—	—	2.0	0.3	2.0	0.3
Total	—	—	—	—	8.0	2.5	8.0	2.5
Total	25.0	10.7	34.0	10.9	68.0	40.2	127.0	63.0

As part of our corporate strategy, we plan to seek to operate our wells where possible and to maintain a high level of participation in our wells by investing our own capital in drilling operations. While our management team has considerable industry experience, to date our company has participated in the drilling of only 11 New Albany Shale wells, and has acted as operator of four those wells.

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Organizational Structure

After giving effect to the Reorganization Transactions, we will have six wholly owned subsidiaries:

Rex Energy I, LLC. After giving effect to the Reorganization Transactions, Rex Energy I, LLC will own all of our remaining properties, including those of Douglas Oil & Gas, Douglas Westmoreland, Midland Exploration, New Albany, Rex I, Rex II, Rex III, Rex II Alpha and Rex Royalties.

Rex Energy Operating Corp. As of the date of this prospectus, Rex Operating owns our entire administrative and clerical infrastructure, and provides administrative services to us and our subsidiaries. Rex Operating serves as the employer for all of our employees and maintains all of our benefit plans.

Penn Tex Energy, Inc. As of the date of this prospectus, Penn Tex Energy, Inc. owns a 1% general partner interest in PennTex Resources, L.P.

PennTex Resources, L.P. As of the date of this prospectus, PennTex Resources, L.P. owns an approximate 25% working interest in certain assets in the Lawrence, St. James and West Kenner Fields in Illinois, and the El Nora field in Indiana.

PennTex Resources Illinois, Inc. As of the date of this prospectus, PennTex Resources Illinois, Inc. owns an approximate 26% working interest in certain assets in the Lawrence, St. James and West Kenner Fields in Illinois, and the El Nora field in Indiana.

Rex Energy IV, LLC. As of the date of this prospectus, Rex Energy IV, LLC owns an approximate 49% working interest in certain assets in the Lawrence, St. James and West Kenner Fields in Illinois, and the El Nora field in Indiana.

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The following diagram depicts our organizational structure after giving effect to the Reorganization Transactions and this offering:

(1) Includes shares owned by Lance T. Shaner, Shaner Family Partners Limited Partnership, RexGuard, LLC, Shaner & Hulburt Capital Partners Limited Partnership and The Lance T. Shaner Irrevocable Grandchildren’s Trust II, which Mr. Shaner effectively controls. Mr. Shaner disclaims beneficial ownership of all equity interests of these entities, other than those which he owns directly under his name.

(2) Includes shares held by management (other than the Shaner Group). These shares held by management represent 14.2% of our outstanding shares.

(3) Reflects the mergers of Douglas Oil & Gas, Douglas Westmoreland, Midland Exploration, New Albany, Rex I, Rex II, Rex III, Rex II Alpha and Rex Royalties with and into Rex Energy I, LLC pursuant to the Reorganization Transactions.

Competition

The oil and gas industry is intensely competitive, particularly with respect to the acquisition of prospective oil and natural gas properties and oil and natural gas reserves. Our ability to effectively compete is dependent on our geological, geophysical and engineering expertise and our financial resources. We must compete against a substantial number of major and independent oil and natural gas companies that have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also have refining operations, market refined products and generate electricity. We also compete with other oil and natural gas companies to secure drilling rigs and other equipment necessary for drilling and completion of wells. Consequently, drilling equipment may be in short supply from time to time. Currently, access to additional drilling equipment in certain regions is difficult.

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Governmental Regulations

Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, some states in which we may operate require permits for drilling operations, drilling bonds or reports concerning operations, and impose other requirements relating to the exploration for and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of wells. Failure to comply with any such rules and regulations can result in substantial penalties. The increasing regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. We may be required to make significant expenditures to comply with governmental laws and regulations, which could have a material adverse effect on our business, financial condition and results of operations.

Our operations are subject to various types of regulation at the federal, state and local levels that:

• require permits for the drilling of wells:

• permits to drill wells on federal lands generally require a minimum of 60-120 days;

• permits to drill wells on state land and fee lands generally require a minimum of 30-60 days;

• mandate that we maintain bonding requirements in order to drill or operate wells; and

• regulate the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, temporary storage tank operations, air emissions from flaring, compression and access roads, sour gas management, and the disposal of fluids used in connection with operations.

Our operations are also subject to various conservation laws and regulations. These regulations govern the size of drilling and spacing units or proration units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of natural gas and oil properties. In this regard, some states allow the forced pooling or integration of lands and leases to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose specified requirements regarding the ratability of production. On some occasions, tribal and local authorities have imposed moratoria or other restrictions on exploration and production activities that must be addressed before those activities can proceed. The effect of all these regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Where our operations are located on federal lands, the timing and scope of development may be limited by the National Environmental Policy Act. The regulatory burden on the oil and natural gas industry increases our costs of doing business and, consequently, affects our profitability. Because these laws and regulations are frequently expanded, amended and reinterpreted, we are unable to predict the future cost or impact of complying with applicable environmental and conservation requirements.

The Federal Energy Regulatory Commission, or FERC, regulates interstate natural gas transportation rates and service conditions. Its regulations affect the marketing of natural gas produced by us, as well as the revenues that may be received by us for sales of such production. Since the mid-1980s, FERC has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B, collectively, Order 636, that have significantly altered the marketing and transportation of natural gas. Order 636 mandated a fundamental restructuring of interstate

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pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other services such pipelines previously performed. One of FERC’s purposes in issuing Order 636 was to increase competition within the natural gas industry. The United States Court of Appeals for the District of Columbia Circuit has largely upheld Order 636 and the Supreme Court declined to hear the appeal from that decision. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation service, and has substantially increased competition and volatility in natural gas markets.

The price we receive from the sale of oil and natural gas liquids will be affected by the cost of transporting products to markets. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, index such rates to inflation, subject to certain conditions and limitations. We are not able to predict with certainty the effect, if any, of these regulations on our intended operations. The regulations may, however, increase transportation costs or reduce well head prices for oil and natural gas liquids.

Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection and the discharge of materials into the environment. These laws and regulations:

• require the acquisition of permits or other authorizations before construction, drilling and certain other of our activities;

• limit or prohibit construction, drilling and other activities on specified lands within wilderness and other protected areas; and

• impose substantial liabilities for pollution that may result from our operations.

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce environmental laws and regulations, and violations may result in fines, injunctions, or even criminal penalties. We believe that we are in substantial compliance with current applicable environmental laws and regulations, and, except for those matters described in “Business—Legal Proceedings,” have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, the trend in environmental legislation and regulation generally is toward stricter standards, and we expect that this trend will continue. Changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry as a whole.

The following is a summary of the existing laws and regulations that could have a material impact on our business operations.

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial condition.

The Comprehensive Environmental, Response, Compensation, and Liability Act, or CERCLA, and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons

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who disposed of or arranged for the disposal of “hazardous substances” found at such sites. The classes of persons considered responsible for a release under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production, and produced water disposal operations for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws.

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Our oil and natural gas exploration and production operations generate produced water as a waste material, which is subject to the disposal requirements of the Clean Water Act, Safe Drinking Water Act, or SDWA, or an equivalent state regulatory program. This produced water is disposed of by re-injection into the subsurface through disposal wells, discharge to the surface, or in evaporation ponds. Whichever disposal method is used, produced water must be disposed of in compliance with permits issued by regulatory agencies, and in compliance with applicable environmental regulations. This water can sometimes be disposed of by discharging it under discharge permits issued pursuant to the CWA or an equivalent state program. Another common method of produced water disposal is subsurface injection in disposal wells. Such disposal wells are permitted under the SDWA, or an equivalent state regulatory program. To date, we believe that all necessary surface discharge or disposal well permits have been obtained and that the produced water has been discharged into the produced water disposal wells in substantial compliance with such obtained permits and applicable laws and regulations.

The Federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. For instance, at least nine states in the Northeast (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York and Vermont) and five states in the West (Arizona, California, New Mexico, Oregon and Washington) have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s

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decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S., or the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse affect on our operations and demand for our products.

The National Environmental Policy Act, or NEPA, requires a thorough review of the environmental impacts of “major federal actions” and a determination of whether proposed actions on federal land would result in “significant impact.” In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. NEPA review can increase the time for obtaining approval of and impose additional regulatory burdens on our exploration and production activities on federal lands, thereby increasing our costs of doing business and our profitability.

Legal Proceedings

General

From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. Except as described below, we do not believe we are party to any legal proceedings which, if determined adversely to us, individually or in the aggregate, would have a material adverse effect on our financial position, results of operations or cash flows.

Resident Complaints Regarding Hydrogen Sulfide Gas Emissions

In approximately 2002, predecessors of PennTex Illinois received complaints from local residents of the cities of Bridgeport and Petrolia, Illinois concerning odors alleged to be emanating from oil wells, emergency pits and facilities located in the Lawrence Field operated by the predecessors of PennTex Illinois. The complainants alleged that the odors were caused by hydrogen sulfide gas, or H₂S, a colorless gas with a distinctive “rotten egg” odor. H₂S is produced from a variety of sources, such as wastewater treatment plants, agricultural operations, paper mills, manufacturing processes and oil and gas operations. The complainants alleged that H₂S gas emissions from the oil wells and associated facilities also caused corrosion damages to HVAC systems and other personal property at each of their residences. Each complainant requested compensation for the repair or replacement of personal items located at their residences. Predecessors of PennTex Illinois entered into settlement agreements with certain of these residents relating to their claims of corrosion damages.

On October 7, 2004, a predecessor of PennTex Illinois (then known as ERG Illinois, Inc.) received a Violation Notice dated October 6, 2004, pursuant to Section 31(a)(1) of the Illinois Environmental Protection Act from the Illinois Environmental Protection Agency (“Illinois EPA”) regarding odors allegedly emanating from its Newell Facility emergency pit or in the general vicinity of the emergency pit. Thereafter, on December 16, 2004, the company received a letter entitled “Request to Provide Information Pursuant to the Clean Air Act” from the U.S. EPA. The U.S. EPA requested information necessary to determine whether the operations surrounding the Newell Facility were in compliance with the Illinois State Implementation Plan and the Clean Air Act. On December 27, 2004, ERG Illinois, Inc. submitted to the Illinois EPA a proposed Compliance Commitment Agreement (“CCA”) that responded to the October 6, 2004 Violation Notice with a denial of the alleged violations, but accompanied by a proposal to periodically clean the emergency pit. On January 26, 2005, the

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Illinois EPA provided a letter to the company indicating that the company’s previously submitted CCA had been accepted, thus resolving the Violation Notice.

On January 12, 2005, our Chairman, Lance T. Shaner, acquired the outstanding capital stock of ERG Illinois, Inc. and changed the company’s name to “PennTex Resources Illinois, Inc.” On January 28, 2005, PennTex Illinois submitted a response to the U.S. EPA’s December 16, 2004 information request. On February 9, 2005, the U.S. EPA requested additional data from PennTex Illinois regarding the quantity of H₂S emissions from various sources including the Newell Facility and the wells in and around the city of Bridgeport, Illinois. In March 2005, PennTex Illinois engaged a third party environmental consulting firm to prepare a Preliminary Action Plan designed to identify and analyze emissions from PennTex Illinois’ operations and to propose recommendations to address any identified concerns. A report entitled “PAP/Odor Investigation Results” with recommendations and a cover letter were sent to the U.S. EPA on July 18, 2005 (the “PAP Report”). The PAP Report concluded that, for all wells monitored, PennTex Illinois was in compliance with all known federal, state and local rules and regulations in regard to H₂S emissions and exposures. The PAP Report recommended that additional H₂S controls, such as the installation of scavenger drums, be implemented with respect to some of the monitored wells. The PAP Report described the results of high range and low range H₂S instrument sampling in the vicinity of the Newell Facility and concluded that no additional operational controls or modifications appeared to be necessary or feasible to further reduce H₂S concentrations in the vicinity of the Newell Facility.

On March 13, 2006, PennTex Illinois received a second information request from the U.S. EPA requesting additional information relating to, among other matters, the company’s installation of flares and scavenger drums to control H₂S emissions at its oil well locations. On March 27, 2006, PennTex Illinois submitted a response to the U.S. EPA’s second information request.

U.S. EPA and U.S. DOJ Enforcement Action

In September 2006, the U.S. DOJ and the U.S. EPA initiated an enforcement action seeking mandatory injunctive relief and potential civil penalties from PennTex Illinois and Rex Operating based on allegations that the companies were violating the Clean Air Act in connection with the release of H₂S and other volatile organic compounds, or VOCs, in the course of PennTex Illinois’ oil operations in the Lawrence Field near the towns of Bridgeport and Petrolia, Illinois. Our senior management met with representatives of the U.S. EPA, U.S. DOJ, Illinois EPA and the Agency for Toxic Substances and Disease Registry (“ATSDR”) on September 7, 2006, to discuss matters relating to the enforcement action. This meeting had been preceded by certain monitoring of air emissions in the areas surrounding Bridgeport and Petrolia that the U.S. EPA and ATSDR had conducted in May 2006.

In October 2006, PennTex Illinois and Rex Operating entered into a non-binding agreement in principle with the U.S. EPA to address matters that were the subject of the pending enforcement action. Pursuant to this agreement, we agreed to develop and carry out a detailed and comprehensive written response plan designed to further reduce possible emissions of H₂S and VOCs from PennTex Illinois’ oil wells and associated facilities in the Lawrence Field that are closest to populated areas. We agreed to operate and maintain the control measures described in the response plan in accordance with a written operations and maintenance plan to be developed by us and approved by the U.S. EPA. The agreement in principle required us to evaluate the effectiveness of the control measures in the Lawrence Field installed pursuant to the response plan through a monitoring program, and required us to evaluate the need for additional control measures at other facilities within the Lawrence Field within 60 days. We also agreed in the agreement in principle to present to the U.S. EPA any recommendations for further action we might develop based upon our observations of the effectiveness of the control measures. The parties also agreed that they would use their best efforts to negotiate a proposed final settlement agreement that would resolve the government’s enforcement action, which settlement agreement would be published in the Federal Register and made subject to public comment prior to any final approval.

In April 2007, PennTex Illinois, Rex Operating and the U.S. EPA and U.S. DOJ executed a comprehensive consent decree in which PennTex Illinois and Rex Operating, without any admission of wrongdoing or liability

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and without any agreement to pay any civil fine or penalty, agreed to install certain control measures and to implement certain operating and maintenance procedures in the Lawrence Field. Under the terms of the proposed consent decree, PennTex Illinois and Rex Operating agreed to establish a monitoring protocol that would be designed to facilitate the reduction of possible emissions of H₂S and VOCs from PennTex Illinois’ operations near Bridgeport and Petrolia. A notice regarding the proposed consent decree was published in the Federal Register on April 19, 2007. The published notice of the proposed consent decree solicited public comments on the terms of the consent decree for a 30 day period expiring on May 21, 2007. The United States did not receive any comments on the proposed consent decree during the public comment period. On June 1, 2007, the United States filed a motion for the approval and entry of the proposed consent decree with the United States District Court for the Southern District of Illinois. On June 6, 2007, the court granted the United States’ motion for approval and entry of the proposed consent decree, thereby resolving the enforcement action according to the terms described in the consent decree. The consent decree does not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree.

Class Action Litigation

PennTex Illinois and Rex Operating are defendants in a putative class action lawsuit that has been filed in the United States District Court for the Southern District of Illinois. This action was commenced on October 17, 2006, by plaintiffs Julia Leib and Lisa Thompson, individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport and Petrolia, Illinois. The complaint asserts that the operation of oil wells that are controlled, owned or operated by PennTex Illinois and Rex Operating has resulted in “serious contamination” of the class area with H₂S. The complaint asserts several causes of action, including violation of the Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct. The complaint seeks, among other things, injunctive relief under the Illinois Environmental Protection Act and Illinois common law, compensatory and other damages, punitive damages, and attorneys’ fees and costs. In addition, the complaint seeks the creation of a court-supervised, defendant-financed fund to pay for medical monitoring for the plaintiffs and others in the class area.

On November 14, 2006, PennTex Illinois and Rex Operating filed a joint answer to the complaint specifically denying virtually all of the allegations in the complaint and asserting affirmative defenses thereto. On December 20, 2006, the plaintiffs filed a motion for class certification requesting that the court certify the case as a class action. On January 26, 2007, the court issued a scheduling and discovery order establishing deadlines for completing discovery and briefing relating to the plaintiffs’ motion for class certification. The order states that after the filing of the last brief on class certification issues on August 31, 2007, the court will schedule a hearing on plaintiffs’ motion for class certification. We intend to vigorously oppose the plaintiffs’ motion for certification of the case as a class action.

On January 31, 2007, the plaintiffs filed a motion for leave seeking permission to file an amended complaint that would add a claim against the defendants for alleged violation of Section 7002(a)(1) of the Resource Conservation And Recovery Act. Plaintiffs’ proposed amended complaint makes factual allegations similar to those previously asserted in the plaintiffs’ prior pleadings. We believe that it is likely that the court will grant the plaintiffs’ motion for leave to file the amended complaint. On February 6, 2007, the court set a final pretrial conference for this case for August 7, 2008. The case is scheduled for jury trial on August 18, 2008, in the United States District Court for the Southern District of Illinois located in Benton, Illinois. The parties to this lawsuit have exchanged initial pretrial disclosures as required under the applicable rules, and each side has served and responded to pre-deposition written discovery.

We believe that there is no evidence that any H₂ S gas emissions from any of our facilities have caused any damage or injury to any person or property, and we intend to vigorously defend against the claims that have been asserted against PennTex Illinois and Rex Operating in this lawsuit. Because this lawsuit was recently initiated,

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however, and because it is usually difficult to predict the outcome of litigation, we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or to estimate the amount or the range of potential loss should the outcome be unfavorable to us. If, as a result of this lawsuit, we are required to pay significant monetary damages, our financial position and results of operations could be substantially harmed.

Pursuant to the terms of a pollution liability policy with Federal Insurance Company, we have insurance coverage for possible damages relating to claims made in this lawsuit for up to $1,000,000. In addition, in accordance with the terms of the pollution liability policy, Federal Insurance Company has agreed to conduct our defense in this lawsuit at the insurer’s expense. Under the terms of a written agreement with us, Federal Insurance Company has agreed to pay a substantial portion of our costs and expenses relating to the defense of this lawsuit, including attorneys’ fees. Under the terms of our agreement, we are required to pay the costs and expenses relating to the defense in excess of the amounts payable by Federal Insurance Company.

Rex IV and PennTex Resources also own non-operated working interests in the same oil wells and related facilities operated by PennTex Illinois that are the subject of this lawsuit. In addition, Rex II, Rex II Alpha and Rex III each own interests in the Illinois Basin, although their interests have not historically been the subject of H₂S complaints or investigations. While we intend to vigorously oppose any attempts to join any of these entities as parties to the class action lawsuit, we cannot assure you that this will not take place. In addition, the interests of these other entities might become subject to similar complaints, investigations or lawsuits in the future.

Employees

As of March 31, 2007 we had 106 full time employees. We are not a party to any collective bargaining agreements. We believe that our relations with our employees are good.

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MANAGEMENT

Executive Officers and Directors

The following table sets forth the name, age and position of our directors and executive officers as of June 30, 2007:

Name	Age	Position
Lance T. Shaner	53	Chairman
Benjamin W. Hulburt	33	Chief Executive Officer and Director
Thomas F. Shields	49	President, Chief Operating Officer and Director
John A. Lombardi	42	Director
Thomas C. Stabley	36	Chief Financial Officer
Christopher K. Hulburt	36	Executive Vice President, Secretary and General Counsel
Jack S. Shawver	48	Vice President & Illinois Basin District Manager
Michael S. Carlson	52	Vice President & Appalachian Basin District Manager
Joe Clement	49	Vice President & Permian Basin District Manager

We expect that within one year of the listing of our common stock on The Nasdaq Global Market our board of directors will be comprised of at least seven persons, at least four of whom will be “independent directors.”

Upon completion of this offering, we expect that our board of directors will be comprised of at least four persons, at least one of whom will be an “independent director,” as that term is defined in the NASDAQ Stock Market rules. John A. Lombardi will be an “independent director” upon completion of this offering. We currently are conducting a search for persons to fill the three remaining “independent director” vacancies. Information about our incumbent directors and executive officers follows.

Lance T. Shaner was named Chairman of Rex Energy in March 2007. Prior to that, Mr. Shaner served as the Chief Executive Officer and Chairman of Rex Operating from March 2004 to September 2006, and Chairman and Chief Executive Officer of Shaner Hotels since its inception in 1984. Mr. Shaner founded PennTex Resources in 1996 and has co-founded and served as an officer of all of the Rex Energy affiliated companies since that time. Mr. Shaner received his Bachelor of Arts degree in History from the University of Alfred.

Benjamin W. Hulburt was named Chief Executive Officer of Rex Energy in March 2007. Prior to that, Mr. Hulburt served as the Chief Executive Officer of Rex Operating since October 2006, President of Rex Operating from March 2004 to October 2006, and Chief Financial Officer for Douglas Oil & Gas from January 2001 to February 2004. Mr. Hulburt co-founded the first Rex Energy partnership in 2001 and has co-founded and has served as an officer of all of the Rex Energy affiliated companies since that time. Prior to November 2001, Mr. Hulburt served on active duty as a commissioned officer in the United States Army for four years, leaving the service holding the rank of Captain. Mr. Hulburt received his Bachelor of Science degree in Finance from Pennsylvania State University. Mr. Hulburt is the brother of Christopher K. Hulburt.

Thomas F. Shields was named President and Chief Operating Officer of Rex Energy in March 2007. Prior to that, Mr. Shields served as the President & Chief Operating Officer of Rex Operating since October 2006, Chief Operating Officer of Rex Operating from March 2004 to October 2006, and Chief Executive Officer of Douglas Oil & Gas and its predecessor Douglas Oil & Gas, Inc. from January 1984 to February 2004. He received his Bachelor of Science degree in Petroleum and Natural Gas Engineering from Pennsylvania State University.

John A. Lombardi was named as a Director of Rex Energy in April 2007. Mr. Lombardi is currently the Chairman of our Compensation Committee and our Audit Committee. He is also a member of our Nominating and Governance Committee. Since February 2007, Mr. Lombardi has been self-employed as an accounting and financial reporting consultant. Mr. Lombardi was the Senior Vice President and Chief Financial Officer for Rent-

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Way, Inc., a publicly traded furniture and electronics rent-to-own company, from December 2005 to February 2007 when the company was acquired by Rent-A-Center, Inc. He was Vice President, Corporate Controller and Chief Accounting Officer of Rent-Way, Inc. from April 2001 to December 2005. From August 1997 to April 2001, Mr. Lombardi served as the Chief Financial Officer and Treasurer at Community Rehab Centers, Inc. During 1996 and 1997, he served as Executive Vice President, Chief Financial Officer and Treasurer of Northstar Health Services, Inc. From 1986 to 1996, Mr. Lombardi worked in the audit, business advisory and specialty consulting services practices of Arthur Andersen LLP. Mr. Lombardi is a certified public accountant, a certified insolvency and reorganization accountant, and a certified fraud examiner. Mr. Lombardi holds a Bachelor of Science degree from Gannon University.

Thomas C. Stabley was named the Chief Financial Officer of Rex Energy in March 2007. Prior to that, Mr. Stabley served as the Chief Financial Officer of Rex Operating since March 2004 and Vice President of Accounting for Shaner Hotels from January 1998 to March 2004. He received his Bachelor of Science degree in Accounting from the University of Pittsburgh.

Christopher K. Hulburt was named Executive Vice President, Secretary and General Counsel of Rex Energy in March 2007. Prior to that, Mr. Hulburt served as the Vice President and General Counsel for each of the Founding Companies since April 2005. From January 2001 until April 2005, Mr. Hulburt was a senior associate for the law firm of Hodgson Russ LLP in its corporate and securities practice group. Prior to joining Hodgson Russ, he served as an officer in the U.S. Army’s Judge Advocate General’s Corps as a military prosecutor beginning in January 1997 and, in his last two years of service, also held the position of Special Assistant United States Attorney for the U.S. Department of Justice. He received his Bachelors degree in History/Education from Niagara University and his law degree from Western New England College School of Law. Mr. Hulburt is the brother of Benjamin W. Hulburt.

Jack S. Shawver was named Vice President & Illinois Basin District Manager for Rex Energy in March 2007. Prior to that, Mr. Shawver served as the Vice President of Operations—Illinois Basin for Rex Operating since January 2005, General Manager for ERG Illinois, Inc., an oil and gas company operating in the Illinois Basin, from January 2004 to December 2004, and the Illinois Basin Business Unit Manager for Plains Exploration and Production Company from January 2002 to December 2003. He received his Bachelor of Science degree in Management of Human Resources from the Oakland City University.

Michael S. Carlson was named Vice President & Appalachian Basin District Manager for Rex Energy in March 2007. Prior to that, Mr. Carlson served as the Vice President of Rex Operating’s Northeast Operations since March 2004, and Vice President of Operations for Douglas Oil & Gas from May 1989 to February 2004. He received his Bachelor of Science degree in Geology from the State University of New York at Fredonia.

Joe Clement was named Vice President & Southwest Region District Manager of Rex Energy in March 2007. Prior to that Mr. Clement served as the Permian Basin District Manager for Rex Operating since July 2006, Senior Operations Engineer for Pogo Producing Corp. from April 2006 to July 2006, Senior Operations Engineer for Latigo Petroleum, Inc. from April 2004 to April 2006 and New Mexico Engineer for Saga Petroleum from March 2002 to April 2004. Mr. Clement received his Bachelor of Science degree in Mechanical Engineering from Texas Tech University.

Code of Business Conduct and Ethics

Upon completion of this offering, we will adopt a written code of business conduct and ethics that applies to our directors, officers and employees, including our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. Following this offering, a current copy of the code will be posted on the Corporate Governance section of our website, which is located at www.rexenergy.com.

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Our Board of Directors

Upon completion of this offering, our board of directors will consist of at least four members, at least one of whom will satisfy the independence requirements of The Nasdaq Global Market and SEC rules. John A. Lombardi, one of our current directors, satisfies the independence requirements of The Nasdaq Global Market and SEC rules. The Nasdaq’s Marketplace Rules require that a majority of the board of directors of a listed company be independent; however, we will rely upon an exemption to this requirement contained in the Nasdaq Marketplace Rules. This exemption provides that a majority of the board of directors of a company listing in connection with their initial public offering must meet the independence requirements of the Nasdaq Marketplace Rules within twelve months from the date of the company’s listing. Therefore, we expect that within one year of the listing of our common stock on The Nasdaq Global Market our board of directors will be comprised of seven persons, at least four of whom will satisfy the independence requirements of The Nasdaq Global Market and applicable SEC rules. Our directors will be elected annually. The board has appointed three functioning committees of the board of directors: an audit committee, a compensation committee and a nominating and governance committee. Each of the audit committee, compensation committee and nominating and governance committee will operate under a charter approved by our board of directors. Upon completion of this offering, current copies of each committee’s charter will be posted on the Corporate Governance section of our website, which is located at www.rexenergy.com.

Upon listing of our common stock on The Nasdaq Global Market, at least one member of the audit, compensation and nominating committees will be an independent director (as defined by The Nasdaq Global Market corporate governance rules and, in the case of the audit committee, SEC rules). John A. Lombardi, as an independent director, will serve on each of these committees. Upon the listing of our common stock on The Nasdaq Global Market, we will rely upon an exemption contained in the Nasdaq Marketplace Rules to the director independence requirements pertaining to committees of the board of directors. This exemption applies only to companies listing in connection with their initial public offering. In accordance with this exemption, within 90 days of the listing of our common stock on The Nasdaq Global Market, we expect that a majority of the members of each committee of our board of directors will be independent directors, and within one year of listing, each such committee will be comprised entirely of independent directors.

Audit Committee

Currently, the sole member of our audit committee is Mr. John A. Lombardi, an independent director in accordance with the independence requirements of the Nasdaq Marketplace Rules. The board of directors has determined that Mr. Lombardi is an audit committee financial expert, as such term is defined in applicable rules and regulations of the SEC. Upon completion of this offering, the audit committee will consist of at least three members. The audit committee will recommend to the board the independent public accountants to audit our financial statements and establish the scope of, and oversee, the annual audit. The committee also will approve any other services provided by public accounting firms. The audit committee will provide assistance to the board in fulfilling its oversight responsibility to the stockholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of our internal audit function. The audit committee will oversee our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that management and the board have established. In doing so, it will be the responsibility of the audit committee to maintain free and open communication between the committee and our independent auditors, the internal accounting function and management of our company.

Upon completion of this offering, the audit committee will consist of Mr. Lombardi (Chair), Mr. Shaner and Mr. Benjamin Hulburt. Mr. Shaner and Mr. Hulburt will not be considered independent directors. We expect that within 90 days of the listing of our common stock on The Nasdaq Global Market, a majority of the members of the audit committee will be independent directors and, within one year of listing, will be comprised entirely of independent directors.

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Compensation Committee

The current sole member of our compensation committee is Mr. Lombardi, an independent director in accordance with the independence requirements of the Nasdaq Marketplace Rules. Upon completion of this offering, the compensation committee will consist of at least three members. The compensation committee will review the compensation and benefits of our executive officers, establish and review general policies related to our compensation and benefits and administer our Long-Term Incentive Plan, which is described below. The compensation committee will determine the compensation of our executive officers. Upon completion of this offering, the compensation committee will consist of Mr. Lombardi (Chair), Mr. Shaner and Mr. Benjamin Hulburt. Mr. Shaner and Mr. Hulburt will not be considered independent directors. We expect that within 90 days of the listing of our common stock on The Nasdaq Global Market, a majority of the members of the compensation committee will be independent directors and, within one year of listing, will be comprised entirely of independent directors.

Nominating and Governance Committee

Currently, the sole member of our nominating and governance committee is Mr. Lombardi, an independent director in accordance with the independence requirements of the Nasdaq Marketplace Rules. Upon completion of this offering, the nominating and governance committee will consist of at least three members. This committee will nominate candidates to serve on our board of directors and approve director compensation. The nominating and governance committee also will be responsible for monitoring a process to assess director, board and committee effectiveness, developing and implementing our corporate governance guidelines and otherwise taking a leadership role in shaping the corporate governance of our company. Upon completion of this offering, the nominating and governance committee will consist of Mr. Lombardi (Chair), Mr. Benjamin Hulburt and Mr. Shields. Mr. Hulburt and Mr. Shields will not be considered independent directors. We expect that within 90 days of the listing of our common stock on The Nasdaq Global Market, a majority of the members of the nominating and governance committee will be independent directors and, within one year of listing, will be comprised entirely of independent directors.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serves as a member of our board of directors or compensation committee, or other committee serving an equivalent function, of any other entity that has one or more of its executive officers serving as a member of our board of directors or compensation committee.

Compensation Discussion and Analysis

This compensation discussion describes the material elements of compensation awarded to, earned by or paid to our Chief Executive Officer, Chief Financial Officer and our three other most highly compensated executive officers, each as named in the tables below. We refer to these officers collectively as “named executive officers.” While this compensation discussion focuses primarily on the information contained in the following tables and related footnotes, as well as the narrative relating to the last completed fiscal year, we also describe compensation actions taken before or after the last completed fiscal year to the extent that such discussion enhances the understanding of our executive compensation programs.

We believe our success depends on the continued contributions of our named executive officers. Our executive compensation programs are designed in accordance with our philosophy of attracting, motivating and retaining experienced and qualified executive officers and directors with compensation that is consistent with comparable public companies and that recognizes individual merit and overall business results. Our policies are also intended to support the attainment of our strategic objectives by tying the interests of our executive officers with those of our stockholders through operational and financial performance goals and equity-based compensation.

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The principal elements of our executive compensation programs are base salary, annual cash incentives, long-term equity incentives in the form of stock options and stock awards, as well as other benefits and perquisites. The other benefits and perquisites provided to our named executive officers consist of life, disability and health insurance benefits, a qualified 401(k) savings plan and paid vacation and holidays. Our salary and benefits are intended to be competitive with similarly situated companies and our objective is to position the aggregate of these elements at a level that is commensurate with our size and sustained performance.

Compensation Committee

The Compensation Committee of our board of directors is responsible for the approval, evaluation and oversight of all of our compensation plans, policies and programs. The primary purpose of the Compensation Committee is to assist our board of directors in establishing and implementing our compensation policies and monitoring our compliance with such policies. Currently, the sole member of our Compensation Committee is John A. Lombardi (Committee Chairman), an independent director in accordance with the Nasdaq Marketplace Rules. Upon completion of this offering, the compensation committee will be increased to three members and will consist of Mr. Lombardi (Chair), Mr. Shaner and Mr. Benjamin Hulburt. Mr. Shaner and Mr. Hulburt will not be considered independent directors. We expect that within 90 days of the listing of our common stock on The Nasdaq Global Market, a majority of the members of the compensation committee will be independent directors and, within one year of listing, will be comprised entirely of independent directors. From time to time, the Compensation Committee may, whenever it deems appropriate, form and delegate authority to various subcommittees.

Responsibilities of the Compensation Committee

We expect that, after completion of this offering, and subject to the ability of our board of directors to amend the Compensation Committee charter, the responsibilities of the Compensation Committee, acting on behalf of the board of directors, will include the following:

• reviewing and approving our corporate goals and objectives relevant to executive compensation;

• reviewing and approving the structure of our executive compensation to ensure that such structure is appropriate to achieve our objectives of rewarding our executive officers appropriately for their contributions to our growth and profitability and our other goals and objectives;

• determining and evaluating the compensation of our Chief Executive Officer and determining the amounts and individual elements of total compensation for the Chief Executive Officer consistent with our corporate goals and objectives;

• determining and evaluating (in conjunction with our Chief Executive Officer) the compensation of our executive officers and approving the individual elements of total compensation for each such person;

• reviewing market data to assess our position with respect to the compensation of our executive officers in order to ensure we are competitive with comparable public companies;

• periodically evaluating the terms and administration of the our annual and long-term incentive plans to assure that they are structured and administered in a manner consistent with our goals and objectives as to participation in such plans, target annual incentive awards, corporate financial goals, actual awards paid to the our executive officers, and total funds reserved for payment under the compensation plans;

• periodically evaluating (and approving any proposed amendments to) existing equity-related plans and evaluating and approving the adoption of any new equity-related plans and determining when it is necessary to modify, discontinue or supplement any such plans or to submit such amendment or adoption to a vote of the full board of directors or our stockholders;

• periodically evaluating the compensation of our directors, including for service on committees of the board and making recommendations to the full board of directors regarding any adjustments in director compensation that the committee considers appropriate;

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• approving any annual retainer or meeting fees for board members and for members of committees of the board and fixing the terms and awards of any stock compensation for members of the board;

• reviewing the sufficiency of the shares available for grant under our Long-Term Incentive Plan, or LTIP, based on our goals for hiring, bonus and retention grants and assessing our competitive position with respect to the level of our equity compensation, vesting schedules and other terms with comparable public companies; and

• preparing the “Report of the Compensation Committee” to be included in our proxy statement for our annual meeting of stockholders.

Compensation Program Objectives

We expect that the objectives of our executive compensation programs will be the following:

• attract and retain talented and experienced executives;

• motivate and reward executives whose knowledge, skills and performance are critical to our success;

• align the interests of our executive officers and stockholders by motivating executive officers to increase shareholder value and rewarding executive officers when shareholder value increases;

• provide a competitive compensation package that is weighted heavily towards pay for performance, and in which total compensation is primarily determined by company and individual results and the creation of shareholder value;

• ensure fairness among the executive management team by recognizing the contributions each executive makes to our success;

• foster a shared commitment among our executive officers by coordinating their company and individual goals; and

• compensate our executive officers accordingly to meet our long-term objectives.

We expect that the Compensation Committee will evaluate the objectives of our executive compensation programs on a regular basis. In determining the objectives of our executive compensation programs, we expect that the Compensation Committee will examine the appropriate matching of compensation to performance with respect to each individual and to the executive group. We expect that the Compensation Committee will be responsible for comparative analysis of our executive compensation programs against others in the industry to ensure that our programs are competitive.

We expect that the Compensation Committee will be responsible for reviewing and making recommendations to our board of directors regarding our executive compensation programs. These programs were implemented to achieve the objectives established by the Compensation Committee for compensating our executive officers. We expect that the Compensation Committee will review our executive compensation programs on an annual basis to determine if such programs are effective in achieving the objectives established by the Compensation Committee. Compensation objectives are established based upon various measurements of profitability, share value enhancement and specific transaction conclusion, with respect to individuals and to the executive group.

To assist management and the Compensation Committee in assessing and determining compensation packages, we expect that the Compensation Committee may, from time to time, engage compensation consultants based upon the specific needs of the Compensation Committee. We expect that the Compensation Committee may contract with the consultants directly and will control and direct the work to be performed.

We expect that the Compensation Committee will meet outside the presence of all of our executive officers to consider the appropriate compensation for our Chief Executive Officer. For all other named executive officers, we expect that the Compensation Committee will meet outside the presence of all executive officers, except our Chief Executive Officer. We expect that our Chief Executive Officer will annually review the performance of

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each named executive officer with the Compensation Committee and will make recommendations to the Compensation Committee with respect to the appropriate base salary, payments to be made under any annual cash bonus plan and the grant of any equity incentive awards under any of our plans. Based in part on these recommendations from our Chief Executive Officer and the other considerations discussed below, we expect that the Compensation Committee will approve the annual compensation package of each of our executive officers, other than our Chief Executive Officer. We expect that the Compensation Committee will analyze the performance of our Chief Executive Officer and determine the base salary, payments to be made under any annual cash bonus plan and the grant of any equity incentive awards under any of our plans. We expect that input or suggestions applicable to group or individual compensation from other executive officers will be solicited by the Compensation Committee.

We expect that compensation for each executive officer will be determined by the Compensation Committee by evaluating such officer’s performance, our performance, and the officer’s impact on our performance. Based upon these evaluations, we expect that the Compensation Committee will determine the compensation for each of our executive officers, consistent with the objectives established by the Compensation Committee. We expect that the Compensation Committee will also compare the compensation (including salary, bonuses, long-term incentives and other types of compensation) paid by us to our executive officers to executive officers of similarly-positioned companies in our industry, specifically other publicly held oil and gas companies of similar size, location of operations, and other similar attributes. We have identified Warren Resources, Inc. (NASDAQ:WRES), Aurora Oil & Gas Corp. (AMEX: AOG), NGAS Resources, Inc. (NASDAQ: NGAS), Edge Petroleum Corp. (NASDAQ: EPEX) and TXCO Resources, Inc. (NASDAQ: TXCO) as our five primary publicly-traded competitors, thus providing a relevant benchmark for comparing our executive officers’ compensation. These competitors are comparable in size, operations, revenues and reserves to us and require executives with similar experience, and we compete against them for employees in all areas and at all levels of expertise, experience and abilities. Our goal in comparing the compensation of our executives to those of our peer group is to ensure that the total compensation of our executives falls within the minimum and maximum compensation levels of our peer group. We expect that the total compensation of each of our executive officers will be set by the Compensation Committee within the minimum and maximum compensation levels of our peer group based upon the factors described above and any other factors and criteria that may be developed by the committee in the future.

We expect that the Compensation Committee will establish specific performance targets that our executive officers must achieve to receive certain types of compensation, including annual bonuses, base pay increases and performance awards under the LTIP. We expect that these performance targets will be accurate indicators of the executive officers’ impact on our operational success and will provide specific standards that will motivate our executive officers to perform in our best interest and in our stockholders’ best interests. We expect that these targets will include performance measures that will increase the value of the company, including net income, EBITDAX, reserve growth and specific major tasks that need to be accomplished to ensure the financial health of the company. We expect that each executive officer’s individual goals will be set based upon those activities within his or her control.

Specifically, we expect that compensation will be based upon a competitive plan but paid based upon a combination of group and individual goals that include meeting or exceeding profitability, oil and gas reserve enhancement, cash flow from operations or other goals established by the board that would enhance the value of our stock. In addition, certain transactional achievements must be achieved each year to ensure our financial health. We expect that each one of the financial, operational or transactional goals will be weighted for each executive officer to match its importance.

Certain Policies of Our Executive Compensation Programs

We have adopted the following material policies relating to our executive compensation programs:

• Allocation between long-term and currently paid out compensation: The compensation we currently pay consists of base pay and annual incentive compensation. The long-term compensation consists

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entirely of awards made under the LTIP. The allocation between long-term and currently paid out compensation is based on an analysis of how our peer companies use long-term and currently paid compensation to compensate their executive officers.

• Allocation between cash and non-cash compensation: It is our policy to allocate all currently paid compensation in the form of cash and all long-term compensation in the form of awards of options to purchase our common stock. We consider competitive market analyses when determining the allocation between cash and non-cash consideration.

• Return of incentive pay: We intend to implement a policy for the adjustment or recovery of awards or payments if performance measures upon which they are based are materially restated or otherwise adjusted in a manner that will reduce the size of an award or payment. This policy will include the return by any executive officer of any compensation based upon performance measures that require material restatement because of such executive officer’s intentional misconduct or misrepresentation.

Our Executive Compensation Programs

Overall, our executive compensation programs are designed to be consistent with the objectives and principals set forth above. The basic elements of our executive compensation programs are summarized in the table below, followed by a more detailed discussion of each compensation program.

Element	Characteristics	Purpose
Base Salary	Competitive to industry	To attract and retain our executives
Incentive Bonus	Based upon individual performance and performance as an executive group	To motivate enhanced share value, short and long term financial growth and stability of the company
Long-Term Equity Incentive Plan Awards	Based upon individual performance and performance as an executive group	To retain and motivate our executives over a longer term
Retirement Savings Opportunity	Competitive to the industry	To enhance our overall executive compensation package
Health & Welfare Benefits	Competitive to the industry	To attract and retain our executives
Other Perquisites	Competitive to the industry	To attract, retain and motivate our executives

All pay elements are cash-based except for the long-term equity incentive program, which is an equity-based award. We consider market pay practices and practices of peer companies in determining the amounts to be paid, what components should be paid in cash versus equity and what portion of a named executive officer’s compensation should be short-term versus long-term. Compensation opportunities for our executive officers, including our named executive officers, are designed to be competitive with peer companies. We believe that a substantial portion of each named executive officer’s compensation should be performance-based.

In determining whether to increase or decrease compensation to our executive officers, including our named executive officers, we take into account annually the changes, if any, in the market pay levels of our peer group, the contributions made by the executive officer, the performance of the executive officer, the increases or decreases in responsibilities and roles of the executive officer, the business needs of the executive officer, the transferability of managerial skills to another employer, the relevance of the executive officer’s experience to other potential employers and the readiness of the executive officer to assume a more significant role with another organization.

In general, compensation or amounts realized by executives from prior compensation from us, such as gains from previously awarded stock options or options awards, are not taken into account in setting other elements of

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compensation, such as base pay, incentive bonuses or awards of stock options under our long-term equity incentive program. With respect to new executive officers, we take into account their prior base salary and annual cash incentives, as well as the contributions expected to be made by the new executive officer, and the business needs and the role of the executive officer with us. We believe that our executive officers should be fairly compensated each year relative to market pay levels of our peer group and the internal pay levels of our executive officers.

Annual Cash Compensation

To attract and retain executives with the ability and the experience necessary to lead us and deliver strong performance to our stockholders, we provide a competitive total compensation package. Base salaries are intended to be competitive with our peer group, while total compensation is intended to exceed that of our peer group, considering individual performance and experience, to ensure that each executive is appropriately compensated.

Base Salary

Annually we review salary ranges and individual salaries for our executive officers. We establish the base salary for each executive officer based on consideration of pay levels of our peer group and internal factors, such as the individual’s performance and experience, and the pay of others on the executive team.

We consider market pay levels among individuals in comparable positions with transferable skills within the oil and gas industry and comparable companies in general industry. When establishing the base salary of any executive officer, we also consider business requirements for certain skills, individual experience and contributions, the roles and responsibilities of the executive and other factors. We believe competitive base salary is necessary to attract and retain an executive management team with the appropriate abilities and experience required to lead us. Approximately 50% to 75% of an executive officer’s total compensation is comprised of base salary, depending on the executive officer’s role with us.

The base salaries paid to our named executive officers are set forth below in the Summary Compensation Table. See “—Summary of Compensation Table.”

Annual Incentive Bonuses

We provide the opportunity for our named executive officers and other executive officers to earn an annual cash incentive award. We provide this opportunity to attract and retain an appropriate caliber of talent for the position and to motivate executives to achieve our annual business goals. We plan to review annual cash incentive awards for our named executive officers and other executive officers annually in January or February to determine award payments for the last completed fiscal year, as well as to establish award opportunities for the current fiscal year.

Other than the individual performance goals associated with Mr. Shawver’s eligibility to receive a monthly performance bonus as described under “—Employment Agreement with Jack S. Shawver,” there were no specific individual performance goals for the 2006 incentive awards. The 2006 incentive awards were determined by Lance T. Shaner and Benjamin W. Hulburt, the stockholders of Rex Operating, based solely upon their assessment of the individual performance of each executive officer. Mr. Shawver’s bonus in 2006 of $65,000 represented an incentive award in the amount of $15,000 and a finder’s fee bonus in the amount of $50,000 paid to Mr. Shawver as a result of two successful acquisition opportunities sourced by Mr. Shawver for the benefit of the company. We do not expect to pay any additional finder’s fee bonuses to Mr. Shawver in 2007 or thereafter. In 2006, Mr. Shawver did not receive a monthly performance bonus as described under “—Employment Agreement with Jack S. Shawver.” Beginning in 2007, we will set our overall corporate performance goals and our actual performance results that may cause differences between the numbers used for the effect of external

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events that are outside the control of our executives, such as natural disasters, litigation, or regulatory changes in accounting or taxation standards. These adjustments may also exclude all or a portion of both the positive or negative effect of unusual or significant strategic events that are within the control of our executive officers but that are undertaken with an expectation of improving our long-term financial performance, such as restructurings, acquisitions or divestitures. We expect that our overall corporate performance goals, as such goals apply to executive compensation, will be set by our compensation committee shortly after the committee is comprised of a majority of independent directors. In addition, we expect that the individual target levels and performance goals for each of our executive officers will be set by our compensation committee at that time. We expect that the compensation committee will be comprised of a majority of independent directors within 90 days of the completion of this offering. We expect that the compensation committee will establish these overall corporate performance goals, and the individual target levels and performance goals for our other executive officers, after having received recommendations on these matters from our Chief Executive Officer.

Long-term Equity Incentive Compensation

We award long-term equity incentive grants under the LTIP to our executive officers, including the named executive officers, as part of our total compensation package.

The LTIP allows for the grant of stock options, stock appreciation rights, restricted stock, stock units, unrestricted stock, dividend equivalent rights and cash awards. The primary purpose of the LTIP is to enhance our ability to attract and retain highly qualified executive officers, directors, key employees, and other persons, and to motivate such persons to continue in our service and to expend maximum effort to improve our business results and earnings, by providing to such persons an opportunity to acquire or increase a direct proprietary interest in our operations and future success.

The Compensation Committee administers the LTIP, selecting participants to receive awards, determining the types of awards, the terms and conditions of the awards, and interpreting the provisions of the LTIP. Please read “—2007 Long-Term Incentive Plan.”

Other Benefits

Retirement Savings Opportunity

All employees may participate in our 401(k) Retirement Savings Plan, or 401(k) Plan, established in 2005. Each employee may make before tax contributions of up to 60% of his or her base salary, subject to the current Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cash compensation for retirement in a tax efficient manner. We have historically matched up to the first 5% of each employee’s base salary for any contributions made by that employee to the 401(k) Plan. We did not make any discretionary contributions in the 2005 or 2006 plan years. We do not provide an option for our employees to invest in our common stock in the 401(k) plan.

Health and Welfare Benefits

All full time employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, dental and vision care coverage, disability insurance and life insurance.

Other Items of Compensation

Our named executive officers and key employees are provided with company paid mobile phones. Currently, each of Messrs. Benjamin Hulburt, Stabley and Christopher Hulburt is provided with an automobile allowance of $400 per month and each of Messrs. Shields and Shawver is provided with access and use of a company vehicle. Following the completion of this offering, each of Messrs Benjamin Hulburt, Shields, Stabley and Christopher Hulburt will be provided with an automobile allowance of $500 per month pursuant to the terms

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of their respective employment agreements to be entered into concurrently with the completion of this offering. Mr. Shawver will continue to have access and use of a company vehicle following the completion of this offering.

Stock Ownership Guidelines

Stock ownership guidelines have not been implemented by the Compensation Committee for our executive officers. Each of our executive officers has entered into a registration rights and lockup agreement covering each executive officer’s common stock in the Company which is not sold in connection with this offering for a period of up to 180 days from the date of this offering (this period may be extended up to 30 additional days as further set forth in the registration rights agreement). After the expiration of the lock-up period, if we decide at any time to file a registration statement with the SEC with respect to any offering of our common stock (subject to certain exceptions as further set forth in the registration rights agreement), we will offer to our executive officers the opportunity to register a portion or all of their remaining common stock in such offering, subject to certain priority rights in favor of us (as further set forth in the registration rights agreement). Please read “Principal and Selling Stockholders—Selling Stockholders.” We will continue to periodically review best practices and reevaluate our position with respect to stock ownership guidelines.

Securities Trading Policy

Our securities trading policy states that our executive officers, including the named executive officers, and directors may not purchase or sell puts or calls to sell or buy our common stock, engage in short sales with respect to our common stock or buy our securities on margin. The purchase or sale of our common stock by our executive officers may only be made during a window of time established by the Compensation Committee with the aid of our legal counsel.

Tax Deductibility of Executive Compensation

Limitations on deductibility of compensation may occur under Section 162(m) of the Internal Revenue Code of 1986 which generally limits the tax deductibility of compensation paid by a public company to its Chief Executive Officer and certain other highly compensated executive officers to $1 million in the year the compensation becomes taxable to the executive officer. There is an exception to the limit on deductibility for performance based compensation that meets certain requirements.

Although deductibility of compensation is preferred, tax deductibility is not a primary objective of our compensation programs. We believe that achieving our compensation objectives set forth above is more important than the benefit of tax deductibility and we reserve the right to maintain flexibility in how we compensate our executive officers, which may result in limiting the deductibility of amounts of compensation from time to time.

Conclusion

We believe the compensation we have provided to each of our executive officers is reasonable and appropriate to facilitate the achievement of our operational objectives. The compensation programs and policies that we and our Compensation Committee have designed effectively incentivize our executive officers on both a short-term and a long-term basis to perform at a level necessary to achieve these objectives. The various elements of compensation combine to align the best interests of our executive officers with the best interests of our stockholders and us in order to maximize stockholder value.

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Executive Compensation

Summary Compensation

The following table sets forth the total compensation awarded to, earned by, or paid to our named executive officers for all services rendered in all capacities to us in 2006.

Name and Principal Position	Year	Salary ($)		Bonus ($)			Stock Awards ($)	Option Awards ($)	All Other Compensation ($)			Total ($)
Lance T. Shaner,     Chairman and Chief Executive Officer(1)	2006	$	254,998	$	25,000		—	—	$	13,283	(2)	$	293,281
Benjamin W. Hulburt,     Chief Executive Officer	2006	$	183,602	$	25,000		—	—	$	26,730	(3)	$	235,332
Thomas F. Shields,     President and Chief Operating Officer	2006	$	183,602	$	15,000		—	—	$	13,616	(4)	$	212,218
Thomas C. Stabley,     Chief Financial Officer	2006	$	132,600	$	15,000		—	—	$	15,175	(5)	$	162,775
Christopher K. Hulburt,     Executive Vice President, Secretary and General Counsel	2006	$	149,224	$	15,000		—	—	$	18,546	(6)	$	182,770
Jack S. Shawver,     Vice President & Illinois Basin District Manager	2006	$	164,427	$	65,000	(7)	—	—	$	16,271	(8)	$	245,698

(1) Lance T. Shaner served as our Chairman and Chief Executive Officer through September 2006, and as our Chairman from October 2006 to present. Following the completion of this offering, Mr. Shaner will not receive a salary for serving as our Chairman, but will be entitled to receive any director compensation, including the monthly cash retainer which may be awarded to our non-employee directors. See “Director Compensation.”

(2) Includes $13,283 for 401K contributions.

(3) Includes a $10,000 relocation bonus, a $400 monthly car allowance and club membership fees of $1,500 and 401(k) contributions of $10,430.

(4) Includes a $400 monthly car allowance for use of a company owned vehicle and 401(k) contributions of $8,816.

(5) Includes a $400 monthly car allowance and club membership fees of $1,500 and 401(k) contributions of $8,875.

(6) Includes a $6,000 relocation bonus, a $400 monthly car allowance and club membership fees of $1,500 and 401(k) contributions of $6,626.

(7) Includes a finder’s fee bonus in the amount of $50,000 paid to Mr. Shawver as a result of two acquisition opportunities sourced by Mr. Shawver.

(8) Includes a $400 monthly car allowance for use of a company owned vehicle and 401(k) contributions of $11,472.

Employment Agreements and Potential Payments Upon Termination or Change in Control

We do not have any other contractual arrangements with our executive officers, nor do we have any compensatory arrangements with our executive officers other than as described below. Under the employment agreements described below, if benefits to which the executive becomes entitled are considered “excess parachute payments” under Section 280G of the Tax Code, then the executive will be entitled to an additional

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“gross-up” payment from us in an amount such that, after payment by the executive of all taxes, including any excise tax imposed upon the gross-up payment, he retains an amount equal to the excise tax imposed upon the payment.

Employment Agreements with Benjamin W. Hulburt, Thomas F. Shields, Thomas C. Stabley and Christopher K. Hulburt

We intend to enter into employment agreements concurrently with the completion of this offering with each of Benjamin W. Hulburt, Thomas F. Shields, Thomas C. Stabley and Christopher K. Hulburt relating to service as our Chief Executive Officer, President & Chief Operating Officer, Chief Financial Officer, and Executive President, Secretary and General Counsel, respectively. The employment agreements are expected to provide for an annual base salary of $225,000 for Benjamin K. Hulburt, $200,000 for Thomas F. Shields, and $185,000 for each of Thomas C. Stabley and Christopher K. Hulburt. Each employment agreement will become effective on the date we consummate this offering and will continue in effect until the earlier of (i) the third anniversary of the effective date of the employment agreement, (ii) termination based on death or disability of the executive, (iii) termination by us of the executive’s employment, and (iv) voluntary termination of employment by the executive. If the executive is employed on the third anniversary of the effective date of the employment agreement, his employment agreement will be automatically extended for a one year period unless we provide the executive timely written notice that we do not intend to extend the term.

Each employment agreement provides that we will pay severance benefits to each executive officer if (i) his employment is involuntarily terminated without cause, (ii) he elects to terminate his employment with good reason (as further set forth in the employment agreement), or, (iii) if following a change in control (as defined in the employment agreement and described below), he elects to terminate his employment with good reason (as further set forth in the employment agreement) in connection with a change in control.

In each such instance, and subject to the terms of the employment agreements, we will pay to the applicable executive officer the following:

• A lump sum in cash equal to the sum of his base salary through the date of termination, any compensation previously deferred by him (together with any accrued interest or earnings thereon) and any accrued vacation pay, to be paid within 30 days following the date of termination;

• All vested benefits to which he is entitled under the terms of the employee benefit plans in which he is a participant on the date of such termination, payable when due under the terms of the plans;

• A lump sum cash severance payment in an amount equal to two times his then base salary, to be paid within 60 days following the date of termination;

• A lump sum in cash equal to the expected value of his annual cash incentive potential for the fiscal year in which such termination occurs prorated to the date of termination, to be paid within 60 days following the date of termination;

• A lump sum equal to the product of (1) the monthly basic life insurance premium applicable to his basic life insurance coverage immediately prior to the date of termination and (2) the number of full and fractional months remaining under the term of the applicable employment agreement; and

• Certain perquisites, other than executive life insurance, being provided to the executive on the date of termination as further set forth in each agreement for the remainder of the term of the applicable employment agreement.

Each employment agreement also provides that, upon a change in control, (i) all options to acquire any of our stock and all stock appreciation rights held by the executive officer will become fully exerciseable, and (ii) all restrictions on any of our restricted stock granted to the executive officer prior to the change in control

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will be removed and the stock will be freely transferable, in each case, regardless of whether the conditions set forth in the relevant award agreements have been fully satisfied.

Under the employment agreements, a “change in control” means:

• Our board of directors is no longer comprised of a majority of incumbent directors, who are defined as directors who were directors on the effective date of the agreements and any successor to an incumbent director whose election, or nomination for election by our stockholders, was approved by the affirmative vote of at least two-thirds of the incumbent directors then on the board of directors; or

• The Company is reorganized, merged or consolidated or the Company or any of our subsidiaries is sold, or all or substantially all of our assets are disposed of, unless (1) all or substantially all of the individuals and entities who were the beneficial owners of our outstanding common stock immediately prior to such transaction beneficially own, directly or indirectly, more than 50% of the then outstanding shares of our common stock of the corporation resulting from such transaction in substantially the same proportions as their ownership immediately prior to such transaction of our outstanding common stock, (2) an individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (excluding any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 30% or more of the then outstanding shares of common stock of the corporation resulting from such transaction, except to the extent that such ownership existed prior to such transaction, and (3) at least a majority of the members of the board of directors of the corporation resulting from such transaction were incumbent directors of our board of directors at the time of the execution of the initial agreement, or of the action of our board of directors, providing for such transaction; or

• Any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) acquires beneficial ownership of 30% or more of the then outstanding shares of our common stock, except for (1) any acquisition directly from us, (2) any acquisition by us, (3) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by us or any entity controlled by us, or (4) any acquisition by any corporation pursuant to a transaction which complies with clauses (1), (2) and (3) of the immediately preceding paragraph.

In the event of involuntary termination without cause, voluntary termination for good reason or voluntary termination for good reason following a change in control, we would owe approximately $553,000, $481,000, $450,000 and $450,000 to Benjamin W. Hulburt, Thomas F. Shields, Thomas C. Stabley and Christopher K. Hulburt, respectively. These amounts are estimates of the amounts that would be paid out to each of our executive officers upon his termination under such circumstances, and were calculated as if we had been in existence, and the employment agreements were effective, as of January 1, 2006, and that termination of each executive officer was effective as of December 31, 2006. The actual amounts to be paid out, if any, can only be determined at the time of such executive officer’s separation from us.

The employment agreements also (i) prohibit the executive officers from disclosing our confidential information, and, (ii) subject to certain exceptions as further set forth in each employment agreement, restrict each executive officer from engaging in any practice or business in competition with us or our affiliates for a period of one year following the date of such executive officer’s termination of employment with us.

Employment Agreement with Jack S. Shawver

Effective May 18, 2006, we entered into an amended and restated employment agreement with Jack S. Shawver relating to service as our Vice President of Operations—Illinois Basin. This agreement amended and restated an employment agreement entered into on June 1, 2005. The employment agreement, as amended, provides for an annual base salary of $180,000, and will continue in effect until the earlier of (i) June 1, 2008, (ii) termination based on death or disability of Mr. Shawver, (iii) termination by us of Mr. Shawver’s employment and (iv) voluntary termination of employment by Mr. Shawver.

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During the term of Mr. Shawver’s employment under the employment agreement, Mr. Shawver is eligible to receive a monthly performance bonus in an amount equal to $5,000 for any month in which the average barrels of oil sold per day from oil wells located in the Illinois Basin equals or exceeds certain target production amounts. Beginning in June 2005, the target production amount was equal to 2,450 barrels of oil per day and thereafter was decreased by 10 barrels of oil each month. Beginning in April 2007, the target production amount was decreased by 9 barrels of oil each month. As of June 1, 2007, the target production amount was equal to 2,226 barrels of oil per day. The target production amount has not been achieved for any month since its inception in June 2005. On June 8, 2007, we and Mr. Shawver agreed to terminate the monthly performance bonus.

In the event that Mr. Shawver’s employment pursuant to the employment agreement is terminated for cause, Mr. Shawver will receive all accrued but unpaid salary through the date of termination, but will be ineligible to receive a monthly performance bonus for the month in which his termination occurs and thereafter. In the event that Mr. Shawver’s employment pursuant to the employment agreement is terminated by us other than for cause, Mr. Shawver will continue to receive payments of base salary for the lesser period of (i) one year or (ii) the remaining term of the employment agreement, and any benefits that he would have been entitled to under the employment agreement for such period. In the event that Mr. Shawver’s employment pursuant to the employment agreement is terminated as a result of voluntary termination by Mr. Shawver, he will receive no salary or other benefits pursuant to the employment agreement other than accrued but unpaid base salary and accrued benefits.

The employment agreement with Mr. Shawver also prohibits him from disclosing our confidential information and, subject to certain exceptions as further set forth in the agreement, restricts him from engaging in any practice or business in competition with us or our affiliates anywhere within a two mile radius of any area of mutual interest or leasehold interest in which we or our affiliates has or had an ownership interest during the term of the employment agreement for a period of one year after the last period for which Mr. Shawver receives compensation pursuant to the employment agreement.

Director Compensation

We did not have any non-employee directors in 2006 and, accordingly, did not pay any compensation to our directors during that time period solely for their service as directors. We currently pay John A. Lombardi, our sole non-employee director, a cash retainer of $5,000 per month. We plan to appoint three additional non-employee directors within one year following the completion of this offering, and plan to pay all of our non-employee directors a cash retainer of $5,000 per month. We may also grant stock options and awards to our non-employee directors. We plan to pay the chairpersons of the audit committee, compensation committee and nominating and governance committee an additional annual cash retainer.

Mr. Shaner currently receives a salary for serving as our Chairman. Following the completion of this offering, Mr. Shaner will not receive a salary for serving as our Chairman, however, he will be entitled to receive any director compensation, including the monthly cash retainer described above, which may be awarded to our non-employee directors.

2007 Long-Term Incentive Plan

Prior to the completion of this offering, we anticipate adopting the Rex Energy Corporation 2007 Long-Term Incentive Plan, or the LTIP. The LTIP provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, unrestricted stock, dividend equivalent rights and cash awards. Directors, executive officers and other employees of us and our subsidiaries, as well as others performing consulting or advisory services for us, will be eligible for grants under the LTIP. The primary purpose of the LTIP is to enhance our ability to attract and retain highly qualified executive officers, directors, key employees, and other persons, and to motivate such persons to continue in our service and to expend maximum effort to improve our business results and earnings, by providing to such persons an opportunity to acquire or increase a direct

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proprietary interest in our operations and future success. The LTIP is not a “qualified plan” within the meaning of section 401 of the Internal Revenue Code of 1986, as amended (the “Code”), and is not intended to be subject to the Employee Retirement Income Security Act of 1974, as amended (“ERISA”). The LTIP will become effective on the date on which it is approved by our stockholders.

The following is a summary of the material terms of the LTIP, but does not include all of the provisions of the LTIP. For further information about the LTIP, we refer you to the complete copy of the LTIP, which we have filed as an exhibit to the registration statement of which this prospectus is a part.

Administration. The LTIP provides for administration by our Compensation Committee. Among the Compensation Committee’s responsibilities are selecting participants to receive awards, determining the form, amount and other terms and conditions of awards, interpreting the provisions of the LTIP or any award agreement and adopting such rules, forms, instruments and guidelines for administering the LTIP as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the LTIP to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the LTIP, including annual incentive awards paid to executive officers subject to section 162(m) of the Code, or covered employees, will satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for Federal income tax purposes.

Shares Available. The LTIP makes available an aggregate number of shares of our common stock, subject to adjustments, equal to up to 10% of the number of shares outstanding immediately after completion of this offering. The aggregate number of shares with respect to which Full Value Awards, as defined in the LTIP, may be granted under the Plan is 50% of the Aggregate Limit. In the event that any outstanding award expires, is forfeited, cancelled or otherwise terminated without the issuance of shares of our common stock or is otherwise settled in cash, shares of our common stock allocable to such award, including the unexercised portion of such award, shall again be available for the purposes of the LTIP. If any award is exercised by tendering shares of our common stock to us, either as full or partial payment, in connection with the exercise of such award under the LTIP or to satisfy our withholding obligation with respect to an award, only the number of shares of our common stock issued net of such shares tendered will be deemed delivered for purposes of determining the maximum number of shares of our common stock then available for delivery under the LTIP.

In the event of a change in capitalization (as defined in the LTIP), adjustments and other substitutions will be made to the LTIP, including adjustments to the maximum number of shares subject to the LTIP, the number and class of shares subject to awards and, if applicable, the exercise price.

Eligibility for Participation. Employees and directors of, and consultants to, us or any of our subsidiaries and affiliates are eligible to participate in the LTIP. The selection of participants is within the sole discretion of the Compensation Committee.

Types of Awards. The LTIP provides for the grant of stock options, stock appreciation rights, restricted stock, stock units, unrestricted stock, dividend equivalent rights and cash awards, which we refer to collectively as the “awards”. The Compensation Committee will determine the terms and conditions of each award, including the number of shares subject to the award, the vesting terms of the award, and the purchase price for each award. Awards may be made in assumption of or in substitution for outstanding awards previously granted by us or our affiliates, or a company acquired by us or with which we combine.

Award Agreement. Awards granted under the LTIP shall be evidenced by award agreements (which need not be identical) that provide additional terms, conditions, restrictions and/or limitations covering the grant of the award, including, without limitation, terms providing for the acceleration of exercisability or vesting of awards in the event of a change of control or conditions regarding the participant’s employment, as determined by the Compensation Committee in its sole discretion; provided, however, that in the event of any conflict between the provisions of the LTIP and any such agreement, the provisions of the LTIP shall prevail.

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Stock Options. The Compensation Committee may grant incentive and non-qualified stock options to participants. Incentive stock options are options to purchase shares of our common stock that are intended to qualify for special tax treatment under section 422 of the Code, or ISOs. Non-qualified stock options, or NSOs, do not qualify for such treatment. The exercise price of options granted under the LTIP may not be less than 100% of the fair market value of a share on the date of grant. In the case of an ISO, the exercise price cannot be less than 110%) of the fair market value of a share on the date of grant if the recipient is a ten-percent stockholder of ours. The term of options may not exceed ten years (for an ISO, five years if the recipient is a ten-percent stockholder). The exercise price may be paid with cash or its equivalent, with previously acquired shares of our common stock, or by other means approved by the Compensation Committee, including by means of a broker-assisted exercise.

Stock Appreciation Rights. The Compensation Committee may, either alone or in connection with the grant of an option, grant stock appreciation rights to participants under the LTIP. Stock appreciation rights granted alone may be exercised at such times and subject to such terms and conditions as the Compensation Committee may impose. Stock appreciation rights that are granted in tandem with options may only be exercised upon the surrender of the right to purchase an equivalent number of shares of our common stock under the related options and may be exercised only with respect to the shares of common stock for which the related options are then exercisable. The term of stock appreciation rights granted under the LTIP cannot exceed ten years. A stock appreciation right entitles a participant to surrender any then exercisable portion of the stock appreciation right and, if applicable, the related option, in exchange for an amount equal to the product of (i) the excess of the fair market value of a share of our common stock on the date preceding the date of surrender over the fair market value of a share of our common stock on the date the stock appreciation right was issued, or, if the stock appreciation right is related to an option, the per share exercise price of the option, and (ii) the number of shares of our common stock subject to the stock appreciation right.

Dividend Equivalent Rights. The Compensation Committee may grant dividend equivalent rights either in connection with awards or as separate awards under the LTIP. Amounts payable in respect of dividend equivalent rights may be payable currently or, if applicable, deferred until the lapsing of restrictions on the dividend equivalent rights or until the vesting, exercise, payment, settlement or other lapse of restrictions on the award to which the dividend equivalent rights relate.

Restricted Stock. The Compensation Committee may grant awards of restricted stock under the LTIP, which, unless the Compensation Committee determines otherwise at the time of grant, carry full voting rights and other rights as a stockholder, including rights to receive dividends and other distributions. Unrestricted shares will be delivered when the restrictions lapse.

Restricted Stock Units. The Compensation Committee may grant stock units under the LTIP, which represent the right of a participant to receive payment upon vesting or on any later date specified by the Compensation Committee. The amount of such payment is equal to the fair market value of a share of our common stock on the date the stock unit was granted, the vesting date, or such other date determined by the Compensation Committee at the time of grant. Payment under a Restricted Stock Unit award will be made by a date that is no later than the date that is two and one-half (2 ¹/2) months after the end of the calendar year in which the Restricted Stock Unit award payment is no longer subject to a substantial risk of forfeiture (as defined for purposes of section 409A of the Code) or at a time that is permissible under section 409A of the Code.

Share Awards. The Compensation Committee may grant share awards under the LTIP as additional compensation for services rendered or in lieu of cash or other compensation to which a participant is entitled.

Performance Awards. The Compensation Committee may grant performance shares and performance units under the LTIP, which will be earned only if performance goals established for performance periods are met. Unless the Compensation Committee determines otherwise at the time of grant, performance shares carry with them full voting rights and other rights as a stockholder, including rights to receive dividends and other distributions. Performance shares represent the right to receive a certain number of shares of our common stock

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on the terms and conditions provided in an award agreement. Performance units are denominated in shares of our common stock or a specified dollar amount and represent the right to receive: (i) in the case of share- denominated performance units, a payment in the amount of the fair market value on the date of grant, vesting or any other date specified by the Compensation Committee or (ii) in the case of dollar-denominated performance units, a specified dollar amount. Performance criteria may be used to measure our performance as a whole or the performance of a business unit, business segment or division, either individually, or alternatively in any combination, and measured either annually or cumulatively over a period of years, on an absolute basis or relative to a pre-established target, to previous years’ results or to a designated comparison group, in each case as specified by the Compensation Committee in an award agreement. The performance goals upon which the payment or vesting of an award to a covered employee that is intended to qualify as performance-based compensation for purposes of section 162(m) of the Code are limited to one or more of the following: earnings per share, total stockholder return, cash return on capitalization, increased revenue, revenue ratios (per employee or per customer), net income, stock price, market share, return on equity, return on assets, return on capital, return on capital compared to cost of capital, return on capital employed, return on invested capital, stockholder value, net cash flow, operating income, earnings before interest and taxes, cash flow, cash flow from operations, cost reductions and cost ratios (per employee or per customer). The Compensation Committee may adjust performance criteria to reflect the impact of specified corporate transactions, accounting or tax law changes or other extraordinary or nonrecurring events, provided that any such modification does not prevent an award from qualifying for the “Performance-Based Exception” under section 162(m) of the Code, which is described below. Payment under a performance unit award will be made by a date that is no later than the date that is two and one-half (2 ¹/2) months after the end of the calendar year in which the performance unit award payment is no longer subject to a substantial risk of forfeiture (as defined for purposes of section 409A of the Code) or at a time that is permissible under section 409A of the Code.

Performance-Based Exception. Under section 162(m) of the Code, we may deduct, for federal income tax purposes, compensation paid to our chief executive officer and four other most highly compensated executive officers only to the extent that such compensation does not exceed $1,000,000 for any such individual during any year, excluding compensation that qualifies as “performance-based compensation”. The LTIP includes features necessary for income from stock options and other performance-based awards under the LTIP to qualify as “performance-based compensation.”

Change in Control. Unless otherwise provided in an award agreement, if a transaction that constitutes a change in control (as defined in the LTIP) occurs, then (i) outstanding options, stock appreciation rights, stock units and restricted stock vest and (ii) outstanding performance units and performance shares vest as if performance objectives were met at the maximum level and participants are entitled to a cash payment in respect of performance units.

Parachute Payments. Under the so-called “golden parachute” provisions of the Code, the accelerated vesting of stock options and benefits paid under other awards in connection with a change in control of a corporation may be required to be valued and taken into account in determining whether participants have received compensatory payments, contingent on the change in control, in excess of certain limits. If these limits are exceeded, a portion of the amounts payable to the participant may be subject to an additional 20% federal tax and may be nondeductible to the corporation.

Termination, Amendment and Other Terms of the LTIP Options and stock appreciation rights are not transferable except as provided by will or the laws of descent and distribution or a qualified domestic relations order, or as the Compensation Committee may determine at or after grant. Restricted stock and performance awards are not transferable until their restrictions lapse. Our board of directors has the right to terminate or amend the LTIP at any time so long as doing so does not impair or adversely alter any outstanding awards or shares acquired under the LTIP without the award holder’s consent. Notwithstanding the foregoing, our board of directors may not amend the LTIP absent stockholder approval to the extent such approval is required by applicable law, regulation or exchange requirement. In the absence of any earlier termination, the LTIP will terminate on the tenth anniversary of the date on which it was adopted by our stockholders.

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THE REORGANIZATION TRANSACTIONS

Historically, we have conducted our operations through several operating partnerships under the common control of Lance T. Shaner, our Chairman, through his direct and indirect ownership interests and other contractual arrangements, as well as under common management of Rex Operating. Pursuant to the Reorganization Transactions, we will combine the operations of these partnerships and companies under a holding company structure upon completion of this offering. Rex Energy Corporation will serve as the parent holding company for this structure.

It has been determined that PennTex Resources, L.P., as the earliest Founding Company formed and by virtue of being wholly owned by Lance T. Shaner, will be considered the accounting acquirer in the merger transactions by which the Company will acquire all of the operations of the Founding Companies. As such, the acquisition of interests in the Founding Companies not owned by Mr. Shaner will be accounted for as a purchase, and the excess of the purchase price over historical book value will be added to the balance sheet of the Company. The economic interests in the Founding Companies not owned by Mr. Shaner are presented as minority interests in our combined financial statements.

The following table shows the level of ownership owned by Mr. Shaner, which are represented in the combined financial statements of our Founding Companies, and the level of minority interests of each of the Founding Companies. The interests listed in the following table as minority interests are the economic interests in these companies which are not owned by Mr. Shaner and which have been presented in our financial statements as minority interests.

		Mr. Shaner’s Interest		Minority Interest(1)
Douglas Oil & Gas Limited Partnership	“Douglas Oil & Gas”	13.70	%	86.30	%
Douglas Westmoreland Limited Partnership	“Douglas Westmoreland”	13.70	%	86.30	%
Rex Energy Royalties Limited Partnership	“Rex Royalties”	5.16	%	94.84	%
Midland Exploration Limited Partnership	“Midland”	2.52	%	97.48	%
New Albany-Indiana, LLC	“New Albany”	40.04	%	59.96	%
PennTex Resources Illinois, Inc.	“PennTex Illinois”	100.00	%	0.00	%
PennTex Resources, L.P.	“PennTex Resources”	100.00	%	0.00	%
Rex Energy Limited Partnership	“Rex I”	22.28	%	77.72	%
Rex Energy II Limited Partnership	“Rex II”	11.10	%	88.90	%
Rex Energy II Alpha Limited Partnership	“Rex II Alpha”	0.00	%	100.00	%
Rex Energy III LLC	“Rex III”	46.50	%	53.50	%
Rex Energy IV, LLC	“Rex IV”	50.00	%	50.00	%
Rex Energy Operating Corp.	“Rex Operating”	60.00	%	40.00	%

(1) Represents the economic interests in these companies not owned by Mr. Shaner, which are represented as minority interests in the combined financial statements of our Founding Companies.

We intend to merge Douglas Oil & Gas, Douglas Westmoreland, Midland, New Albany, Rex I, Rex II, Rex III, Rex II Alpha and Rex Royalties with and into Rex Energy I, LLC, with Rex Energy I, LLC being the surviving entity of each of such mergers. Mr. Shaner controls Douglas Oil & Gas, Douglas Westmoreland, Midland, Rex I, Rex II, Rex II Alpha and Rex Royalties through his direct ownership and control of the general partners of these limited partnerships. Mr. Shaner controls New Albany through his control of the managing member of the company. Mr. Shaner controls Rex III through his indirect control of the voting interests of the company. Each of the holders of the equity interests of such entities will receive for his, her or its equity interests in such entity a specified number of shares of our common stock based upon an exchange ratio that has been agreed to among us and the equity interest holders of such entities. Following completion of the Reorganization Transactions, Rex Energy I, LLC will continue as our wholly owned subsidiary.

In addition, each of the holders of the equity interests of PennTex Illinois (wholly owned by Mr. Shaner), Rex IV (50% owned by Mr. Shaner) and which Mr. Shaner controls through his control of the board of managers

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and Rex Operating (60% owned by Mr. Shaner) will exchange his, her or its equity interests in such entity for a specified number of shares of our common stock based upon an exchange ratio that has been agreed to among us and the equity interest holders of such entities, and each of such entities will become our wholly owned subsidiaries. Mr. Shaner, who owns 100% of the outstanding capital stock of Penn Tex Energy, Inc. (“Penn Tex Energy”), the general partner of PennTex Resources, L.P. (“PennTex Resources”), will exchange all of his shares of Penn Tex Energy for a specified number of shares of our common stock based upon an exchange ratio that has been agreed to between us and Mr. Shaner, and Penn Tex Energy will become our wholly owned subsidiary. Mr. Shaner, who is the sole limited partner of PennTex Resources, will exchange his limited partner interests in PennTex Resources for a specified number of shares of our common stock based upon an exchange ratio that has been agreed to among us and Mr. Shaner, and we will become the sole limited partner of PennTex Resources.

The valuation methodology used to determine the exchange ratio of shares in the Company for equity interests in each of the Founding Companies was determined using a net asset value methodology that was based on the estimated relative values of each of the Founding Company’s assets and liabilities. The valuation methodology used in determining the value of each of the Founding Companies was determined by members of our management, and not by an independent third party; however, the board of directors of Rex Operating engaged the firm of Sanders Morris Harris, Inc. (“Sanders Morris”), an independent third party, to render an opinion to the board of Rex Operating or similar governing body of each Founding Company with respect to the fairness of the Reorganization Transactions from a financial point of view to each non-management equity interest holder (collectively the “Non-Management Equity Holders”) of each Founding Company. Non-management equity interest holders include all holders of equity interests in the Founding Companies other than management and affiliates of management. The following individuals and entities are not considered non-management equity interest holders: Lance T. Shaner, The Lance T. Shaner Irrevocable Grandchildren’s Trust II, Shaner Family Partners Limited Partnership, Shaner and Hulburt Capital Partners Limited Partnership, Benjamin W. Hulburt, Thomas F. Shields, Christopher K. Hulburt, Thomas C. Stabley, Jack Shawver, Michael J. Carlson, Andrew M. Joyner and W. Douglas Gouge. Sanders Morris determined in their fairness opinion that in each case the valuation methodology used was consistently applied, was consistent with precedent or reasonable when compared to customary industry valuation methodologies and was fair from a financial point of view to the Non-Management Equity Holders of each of the Founding Companies. See “—Fairness Opinion.” The consent to the Reorganization Transactions was obtained by each of the Founding Companies after each Founding Company had received the requisite consents from the equity interest holders of such Founding Company.

The exchange ratio of shares to be received by equity interest owners of the Founding Companies is based on the valuation methodology discussed above.

Founding Company	Total Shares to Founding Company	Shares Issued per 1% Equity Interest in Founding Company
Douglas Oil & Gas	1,029,276	10,293
Douglas Westmoreland	640,009	6,400
Midland Exploration	82,639	826
New Albany	1,512,320	15,123
Rex I	20,112	201
Rex II	3,529,479	35,295
Rex III	2,347,392	23,474
Rex II Alpha	127,269	1,273
Rex Royalties	353,115	3,531
Rex Operating	278,152	2,782
PennTex Resources(1)	2,972,350	29,723
PennTex Illinois	3,831,393	38,314
Rex IV	5,271,187	52,712
Total	21,994,692

(1) Includes shares attributable to PennTex Energy, Inc., the 1% owner and general partner of PennTex Resources.

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The consummation of the Reorganization Transactions is conditioned upon the consummation of this offering as described in this prospectus.

The following diagram depicts our organizational structure after giving effect to the Reorganization Transactions and this offering:

(1) Includes shares owned by Lance T. Shaner, Shaner Family Partners Limited Partnership, RexGuard, LLC, Shaner & Hulburt Capital Partners Limited Partnership and The Lance T. Shaner Irrevocable Grandchildren’s Trust II, which Mr. Shaner effectively controls. Mr. Shaner disclaims beneficial ownership of all equity interests of these entities, other than those which he owns directly under his name.

(2) Includes shares held by management (other than the Shaner Group). These shares held by management represent 14.2% of our outstanding shares.

(3) Reflects the mergers of Douglas Oil & Gas, Douglas Westmoreland, Midland Exploration, New Albany, Rex I, Rex II, Rex III, Rex II Alpha and Rex Royalties with and into Rex Energy I, LLC pursuant to the Reorganization Transactions.

Founding Companies and Current Organizational Structure of Rex Entities

In general, prior to the consummation of the Reorganization Transactions, each of the Founding Companies has operated independently, with Rex Operating providing administrative, consulting and operating services to each of the Founding Companies. Set forth below is a brief description of each of the Founding Companies that we will acquire as a result of the Reorganization Transactions. Reserve estimates and present values for proved reserves in the following paragraphs are based on an evaluation of our reserves on a consolidated basis by Netherland Sewell & Associates, Inc. as of December 31, 2006, attached to this prospectus as Appendix A. The reserve and PV-10 information included in this section has been prepared in accordance with SEC regulations.

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Douglas Oil & Gas Limited Partnership

Douglas Oil and Gas Limited Partnership, a Delaware limited partnership, was formed in 2003 through a contribution of assets and liabilities from Douglas Oil & Gas, Inc. and Rex I. Rex Energy LLC, which is 100% owned by Rex I, is the general partner of Douglas Oil & Gas. Douglas Oil & Gas (and its predecessor Douglas Oil & Gas, Inc.) has been an independent oil and gas producer with an emphasis on the development of natural gas reserves in the United States since 1984. Historically, Douglas Oil & Gas has been involved in natural gas exploration projects in the Appalachian Basin. At December 31, 2006, Douglas Oil & Gas operated 165 wells located in the Appalachian Basin, primarily in western Pennsylvania. Douglas Oil & Gas also participates in a joint venture to drill gas wells in Fayette County, Pennsylvania, and a joint venture to provide coalmine methane in West Virginia. Additionally, Douglas Oil & Gas is an 18.63% member in New Albany-Indiana, LLC. As of December 31, 2006, Douglas Oil & Gas’s proved properties totaled 4.3 Bcf natural gas and 97,570 barrels of oil (a total of 813 MBOE) with a PV-10 of $8.8 million.

Douglas Westmoreland Limited Partnership

Douglas Westmoreland Limited Partnership, a Delaware limited partnership, was formed in 2004. Rex Energy LLC is the general partner of the partnership. Douglas Oil & Gas is the sole limited partner. Douglas Westmoreland engages in the exploration, acquisition, management, leasing, development, and extraction of natural gas from underground reservoirs. Douglas Westmoreland owns a 100% working interest in approximately 73 natural gas wells located in Westmoreland County, Pennsylvania. As of December 31, 2006, Douglas Westmoreland’s proved properties totaled 5.8 Bcf of natural gas (a total of 961 MBOE) with a PV-10 of $8.3 million.

Midland Exploration Limited Partnership

Midland Exploration Limited Partnership, a Delaware limited partnership, was formed in October 2004 for the purpose of evaluating, generating and acquiring oil and gas prospects or producing properties in various locations throughout the Permian Basin of Texas and New Mexico. Douglas Oil & Gas is the general partner of Midland Exploration. In the Permian Basin, Midland Exploration has primarily focused on the generation of Atoka/Morrow prospects primarily in southeast New Mexico. At December 31, 2006, Midland Exploration owned interests in 19 wells in New Mexico and 3 wells in Texas. As of December 31, 2006, Midland Exploration’s proved properties totaled 0.4 Bcf of natural gas and 1,344 barrels of oil (a total of 64 MBOE) with a PV-10 of $802,800.

New Albany-Indiana, LLC

New Albany-Indiana, LLC, a Delaware limited liability company, was formed in November 2005 for the purpose of acquiring working interests in leasehold acreage believed to contain New Albany Shale formations in the Illinois Basin, located in southern Indiana. Rex Operating originally was a 49% member of New Albany, but in January 2006, Rex Operating withdrew as a member and assigned its membership interests to Lance T. Shaner, Shaner & Hulburt Capital Partners Limited Partnership, Rex II, Douglas Oil & Gas and Rex Energy Wabash, LLC. Baseline Oil & Gas Corp., or Baseline, originally was a 50% member of New Albany. In March 2007, New Albany redeemed the 50% of its equity owned by Baseline in exchange for a distribution of 50% of its assets, and New Albany is now our wholly owned subsidiary. Rex Energy Wabash, LLC (wholly owned by Shaner & Hulburt Capital Partners Limited Partnership) is the managing member of New Albany.

In February and March 2006, New Albany acquired certain oil and gas leases in Indiana from Aurora Energy Ltd., an option to acquire a 50% working interest in certain other acreage leased or acquired by Aurora or its affiliates and a 45% percent working interest in certain oil, gas and mineral leases in Indiana from Source Rock Resources, Inc. Please read “Business” for more information regarding the Company’s New Albany Shale Project.

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Rex Energy Limited Partnership

Rex Energy Limited Partnership, a Delaware limited partnership, was formed in 2002. Rex I was formed to acquire, own, operate, manage, lease, mortgage, develop and sell or otherwise dispose of, directly or indirectly, working interests and royalty interests in oil and gas producing properties and wells and related property. In January 2003, Rex I combined its assets consisting of certain producing oil and gas wells in Texas and $4.4 million in cash, with Douglas Oil & Gas, Inc., to form Douglas Oil & Gas. Rex I is a 60.55% limited partner in Douglas Oil and Gas. Rex Energy, LLC, a wholly owned subsidiary of Rex I, serves as the 1% owner and general partner of each of Douglas Oil & Gas and Douglas Westmoreland. LT Shaner, LLC, which is controlled by Mr. Shaner, is the general partner of Rex I. In addition to its ownership of Douglas Oil & Gas, Rex I owns working interests in approximately 16 wells in Fayette County, Pennsylvania, with total proved reserves of 53,258 Mcf (8,876 BOE) of natural gas with a PV-10 of $130,300.

Rex Energy II Limited Partnership

Rex Energy II Limited Partnership, a Delaware limited partnership, was formed in September 2004. Rex II completed its capital raising activities in January 2006 with a final equity capitalization of $24.5 million. Rex II began making investments in October 2004, and has since completed a series of acquisitions in the Illinois and Permian Basins. Rex Energy II, LLC is the general partner of Rex II. As of December 31, 2006, Rex II’s proved reserves totaled 5.7 Bcf of natural gas and 1.8 million barrels of oil (2.77 MMBOE) with a PV-10 of $36.5 million.

Rex Energy III LLC

Rex Energy III LLC, a Delaware limited liability company, was formed in October 2004. Shaner Family Partners L.P. (41.85% economic interest), The Lance T. Shaner Irrevocable Grandchildren’s Trust II (4.65% economic interest), Benjamin W. Hulburt (15% economic interest), Thomas F. Shields (10% economic interest), Thomas C. Stabley (8.33% economic interest), Christopher K. Hulburt (8.33% economic interest), Michael S. Carlson (4.17% economic interest), and Jack S. Shawver (4.17% economic interest) collectively own 96.5% of the membership interests of Rex III. The remaining 3.5% membership interest in Rex III is owned by siblings of Lance T. Shaner and certain employees of Shaner Hotel Group Limited Partnership. Shaner Family Partners Limited Partnership, The Lance T. Shaner Irrevocable Grandchildren’s Trust II, and Messrs. B. Hulburt and Shields have a 45.1%, 5.1%, 24.9% and 24.9% voting interest in Rex III, respectively. In June 2006, Rex III acquired certain Illinois basin properties of Team Energy, L.L.C. and certain of its affiliates for $22.7 million. The acquired properties are located in Gibson County and Posey County in Indiana and Lawrence County in Illinois. As of December 31, 2006, Rex III’s proved properties totaled 1.8 million barrels of oil with a PV-10 of $42.7 million.

Rex Energy II Alpha Limited Partnership

Rex Energy II Alpha Limited Partnership, a Delaware limited partnership, was formed in 2004 primarily to acquire, own, operate, manage, lease, develop, and sell or otherwise dispose of, directly or indirectly, interests in producing oil and gas properties and wells (and property related to or used in connection with the foregoing), to make loans for the acquisition and development of oil and gas properties and pipelines, in each case together with Rex II in proportion to the capital accounts of Rex II Alpha and Rex II. Rex Energy II, LLC, which is controlled by Mr. Shaner, Thomas F. Shields and Benjamin W. Hulburt, is the general partner of Rex II Alpha, and IL Venture Capital, LLC, an unaffiliated third party, is the sole limited partner of Rex II Alpha. Rex II Alpha has invested on a “side-by-side” basis with Rex II in substantially all investments made by Rex II for interests ranging from 3% to 10% of such investments. As of December 31, 2006, Rex II Alpha’s proved properties totaled 76,372 barrels of oil and 203,100 Mcf of natural gas (a total of 110,222 BOE) with a PV-10 of $1.37 million.

Rex Energy Royalties Limited Partnership

Rex Energy Royalties Limited Partnership, a Delaware limited partnership, was formed in September 2002. Douglas Oil & Gas (originally with a 10% economic voting interest) is the general partner of Rex Royalties. In

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January 2005, Douglas Oil & Gas assigned its economic interest, including a 10% economic interest before Capital Return and a 30% economic interest after Capital Return, to Shaner & Hulburt Capital Partners Limited Partnership for $140,000. Douglas Oil & Gas retained a 20% economic interest after Capital Return in the partnership. Rex Royalties’ purpose is to acquire, own, operate, manage, lease, develop, or otherwise dispose of royalty interests in proved and producing natural gas wells. Rex Royalties does not engage in the acquisition of working interests in oil and gas properties, or engage in the exploration, development, production, or operational activities with respect to any oil and gas property. In March 2004, Rex Royalties acquired royalty interests in approximately 73 natural gas wells operated by Douglas Westmoreland and royalty interests in gas sales associated with transportation contracts on third-party wells. Rex Royalties earns royalty income from the production of natural gas at these wells. The royalty interests in these wells range from 5% to 35%. As of December 31, 2006, Rex Royalties’ proved properties totaled 803,006 Mcf (a total of 133,834 BOE) with a PV-10 of $2.4 million.

Rex Energy Operating Corp.

Rex Energy Operating Corp. was incorporated in Delaware in October 2004. Messrs. Shaner and B. Hulburt own 60% and 40%, respectively, of the outstanding common stock of Rex Operating. Rex Operating provides management services to all of our oil and gas properties and receives fees for administrative and oil field services to all of the Founding Companies.

PennTex Resources, L.P.

PennTex Resources, L.P., a Texas limited partnership, was formed in November 1997 by its general partner, Penn Tex Energy, Inc., which was owned 100% by Mr. Shaner, and by Mr. Shaner (59%) and Thomas J. Taylor (40%) as limited partners. In September 2005, the partners agreed to a redemption of Mr. Taylor’s limited partnership interest. In consideration for the redemption of his 40% limited partnership interest, Mr. Taylor received the ownership interests in all wells of PennTex Resources located in the states of Texas, Oklahoma, Arkansas, Louisiana and New Mexico. The value of the partnership redemption was $11.1 million, of which $7.7 million was distributed in cash, and the remaining $3.4 million was distributed as the net book value of property. As a result of this redemption, Mr. Shaner now owns 100% of the partnership’s equity interests. PennTex Resources engages in the acquisition of ownership interests in oil and natural gas reserves. PennTex Resources owns a 25% working interest in the Lawrence, West Kenner, St. James and El Nora fields in the Illinois Basin, all of which are operated by PennTex Illinois. As of December 31, 2006, PennTex Resources’ proved properties totaled 1.9 million barrels of oil with a PV-10 of $24.4 million. We plan to implement the Company’s ASP Flood project in the Lawrence Field. Please read “Business” for more information regarding the Company’s Lawrence Field ASP Flood Project.

PennTex Resources Illinois, Inc.

In January 2005, Mr. Shaner acquired 100% of the common stock of PennTex Resources Illinois, Inc., a Delaware corporation, formerly known as ERG Illinois, Inc., from ERG Holdings, Inc. PennTex Illinois engages in the operation and acquisition of oil and gas ownership interests. PennTex Illinois owns a 26% operated interest in the Lawrence, West Kenner, St. James and El Nora fields in the Illinois Basin. As of December 31, 2006, PennTex Illinois’ proved properties totaled 2.0 million barrels of oil with a PV-10 of $25.4 million. We plan to implement the Company’s ASP Flood project in the Lawrence Field, which is owned 26% by PennTex Illinois. Please read “Business” for more information regarding the Company’s ASP Flood Project.

Rex Energy IV, LLC

Rex Energy IV, LLC, a Delaware limited liability company, was formed in September 2006. Messrs. Shaner (50% economic interest), B. Hulburt (15% economic interest), Shields (7% economic interest), Stabley (7% economic interest), C. Hulburt (7% economic interest), Carlson (7% economic interest) and Shawver (7%

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economic interest) are the members of Rex IV. Messrs. Shaner, B. Hulburt and Shields have a 50%, 25% and 25% voting interest in Rex IV, respectively. Rex IV is governed by a board of managers comprised of the voting members of the company. In the event of a tie in any vote of the members, Mr. Shaner casts the deciding vote. In October 2006, Rex IV acquired a 49% non-operating interest in the Lawrence, West Kenner, St. James and El Nora fields in the Illinois Basin, which are all operated by PennTex Illinois. As of December 31, 2006, Rex IV’s proved properties totaled 3.8 million barrels of oil with a PV-10 of $49.5 million. We plan to implement the Company’s ASP Flood Project in the Lawrence Field. Please read “Business” for more information regarding the Company’s ASP Flood Project.

Fairness Opinion

Sanders Morris Harris, Inc., or Sanders Morris, was retained by the board of directors of Rex Operating to render an opinion to the board or similar governing body of each Founding Company with respect to the fairness of the Reorganization Transactions from a financial point of view to the Non-Management Equity Holders of the Founding Companies in the following respects:

• the valuation methodology used to arrive at a value for the equity interests of each of the Founding Companies is consistently applied across entities;

• the valuation methodology used to arrive at a net value for each Founding Company is consistent with precedent or reasonable when compared to customary valuation methodologies used in reorganization transactions similar to the Reorganization Transactions involving companies similar to the Founding Companies; and

• the allocation of shares of our common stock to the non-management equity interest holders of each Founding Company that would be effective following the Reorganization Transactions is fair to such equity holders from a financial point of view.

On March 15, 2007, Sanders Morris formally rendered the above opinions, which it found to be true for each Founding Company in each case, to the board of directors or similar governing body of each of the Founding Companies. Sanders Morris is a nationally recognized investment banking firm which in the ordinary course of its investment banking business is regularly engaged in the valuation of companies and their securities in connection with mergers and acquisition and other corporate transactions. Sanders Morris was selected to render the above opinions because of its expertise and its reputation in investment banking and mergers and acquisitions.

The Sanders Morris opinion is directed to the board of directors or similar governing body of each of the Founding Companies and addresses only the fairness of the Transaction from a financial point of view to each non-management equity interest holder of the Founding Companies as set forth above. The opinion does not address the merits of the underlying business decisions of the Founding Companies to engage in the Reorganization Transactions or any other matter in connection with the Reorganization Transactions.

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PRINCIPAL AND SELLING STOCKHOLDERS

The following table sets forth the currently estimated owners of our common stock that will be issued and outstanding upon consummation of the Reorganization Transactions, but before giving effect to this offering, and held by (i) beneficial owners of 5% or more of our common stock, (ii) each of our directors and executive officers and their affiliates, (iii) all of our directors and executive officers as a group and (iv) each of the Selling Stockholders. After reasonable inquiry, other than as described below or elsewhere in this prospectus, we are not aware of any selling stockholder that has, or has had in the past three years, any position, office or other material relationship with the Company or its predecessors or affiliates.

Beneficial Owner(a)	Shares Beneficially Owned Prior to Offering			Shares Offered	Shares Beneficially Owned After Offering
	Number	Percentage			Number	Percentage
Directors and Executive Officers:
Lance T. Shaner(b)	13,557,180	61.64	%	2,793,015	10,764,165	34.51	%
Benjamin W. Hulburt(c)	1,417,959	6.45	%	141,611	1,276,348	4.09	%
Thomas F. Shields(d)	1,434,317	6.52	%	—	1,434,317	4.60	%
Thomas C. Stabley(e)	603,868	2.75	%	59,900	543,968	1.74	%
Christopher K. Hulburt	586,074	2.66	%	58,607	527,467	1.69	%
Michael S. Carlson	494,710	2.25	%	24,736	469,975	1.51	%
Jack S. Shawver	488,737	2.22	%	48,874	439,863	1.41	%
Andrew M. Joyner	17,919	*		1,792	16,127	*
All Executive Officers and Directors as group	18,600,764	84.57	%	3,128,535	15,472,230	49.60	%
Shaner Family Partners L.P.     1965 Waddle Road State College, PA 16803	1,464,871	6.66	%	585,948	878,923	2.82	%
The Parker Family Limited Partnership(f)	394,636	1.79	%	157,854	236,782	*
Andrew & Laura Zimmerman	13,160	*		4,606	8,554	*
Andrew Maten	13,160	*		1,974	11,186	*
Ann M. Meranus Trust	6,576	*		2,630	3,946	*
Armstrong Tallahasee Associates, LP	40,997	*		16,399	24,598	*
Arthur J. & Paige L. Nagle	26,303	*		9,206	17,097	*
Bunker Partners, L.P.	13,160	*		5,264	7,896	*
Charles C. & Virginia M. Pearson	32,879	*		9,864	23,015	*
Cheryl R. Georgusis	32,879	*		13,152	19,727	*
Daniel E. Beren	13,425	*		5,370	8,055	*
Daniel T. Rockwell	13,152	*		5,261	7,891	*
David & Loraine Pawlush	13,425	*		5,370	8,055	*
David M. & Janell F. Becker	6,576	*		2,630	3,946	*
Donald L. & Sherene Mackos	6,576	*		2,630	3,946	*
Douglas Oil & Gas, Inc.(g)	695,418	3.16	%	278,167	417,251	1.34	%
Ellen L. Joliet	10,965	*		548	10,417	*
Felix & Janice Gutierrez	13,160	*		5,264	7,896	*
Four Fun, L.P.	13,160	*		5,264	7,896	*
G.A. & M.S. Hanks Limited Partnership	46,031	*		18,412	27,619	*
Galen Limited Partnership	52,624	*		21,050	31,575	*
The Gary Fey Restated Trust	6,576	*		2,630	3,946	*
Georgia L. Gian	26,303	*		6,576	19,727	*
Gregory J. Gian	6,576	*		658	5,918	*
Hintz Family Partners, L.P.	170,971	*		68,388	102,583	*
HIRKA, L.P.	13,160	*		5,264	7,896	*
Hoover Associates	65,758	*		26,303	39,455	*

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Beneficial Owner(a)	Shares Beneficially Owned Prior to Offering			Shares Offered	Shares Beneficially Owned After Offering
	Number	Percentage			Number	Percentage
Hospitality Lodging Associates, Inc.	13,160	*		5,264	7,896	*
IL Venture Capital, LLC	120,551	*		48,220	72,331	*
J & F Partners, L.P.	13,425	*		5,370	8,055	*
J & S Oil, L.L.C.	39,455	*		15,782	23,673	*
J. Todd Shields(h)	26,303	*		10,521	15,782	*
James H. & Melinda M. Luther	6,576	*		2,630	3,946	*
Jeanne M. Frensky	3,288	*		1,151	2,137	*
Jeffrey Kirschner	3,288	*		1,315	1,973	*
Jeffrey P. Parker(i)	567,476	2.58	%	16,530	550,946	1.77	%
Joel A. Maten	39,481	*		15,792	23,689	*
John B. Griffin	10,965	*		4,386	6,579	*
John B. & Mary P. Griffin	6,576	*		2,630	3,946	*
John C. & Lynda C. Powell	13,152	*		5,261	7,891	*
John H. Soler & Sandra G. Soler	6,576	*		1,315	5,261	*
John T. Luther	13,152	*		5,261	7,891	*
John W. Overbeck Living Trust	6,576	*		2,630	3,946	*
Joseph C. & Margaret R. Seta	6,576	*		2,630	3,946	*
The Joseph L. Steiner & Marjorie S. Steiner Foundation	6,576	*		2,630	3,946	*
Joseph W. & Marilyn P. Hirschhorn	6,576	*		2,630	3,946	*
Julie W. Parker	8,686	*		3,474	5,212	*
June D. Rudy	26,303	*		10,521	15,782	*
Justin L. Shaner	6,576	*		1,644	4,932	*
Kenneth Ki-Jana Carter	6,576	*		2,630	3,946	*
Kirschner Brothers Profit Sharing Trust	19,727	*		7,891	11,836	*
L and N Oil and Gas, LLC	131,516	*		52,606	78,910	*
Lion Investments II, L.P.	13,425	*		5,370	8,055	*
Lion Investments, L.P.	13,160	*		5,264	7,896	*
Lisa Parker Haggerty	8,357	*		3,343	5,014	*
Lora Parker	18,688	*		7,475	11,213	*
M. Michael Arjmand	13,152	*		5,261	7,891	*
Magic Partners, L.P.	13,160	*		5,264	7,896	*
Maria C. Capule	6,576	*		1,315	5,261	*
Mark Kirschner	3,280	*		1,312	1,968	*
Michael W. Mentzer	3,288	*		1,315	1,973	*
Michael S. Kirschner	13,152	*		5,261	7,891	*
Milestone, L.P.	13,160	*		5,264	7,896	*
NDLD Partners, L.P.	13,425	*		5,370	8,055	*
Ned E. Wehler	13,425	*		5,370	8,055	*
Ned Joseph Gian	6,576	*		1,644	4,932	*
Neurological Surgery, LTD. Profit Sharing Plan	13,425	*		5,370	8,055	*
Park Investments, Ltd.	131,516	*		52,606	78,910	*
Peaches, L.P.	13,160	*		5,264	7,896	*
Peter K. Hulburt(j)	20,171	*		5,000	15,171	*
PPG 1994 Ins. Trust, Ward F. Cleary, Trustee	13,152	*		3,288	9,864	*
R & S Limited Partnership	13,160	*		5,264	7,896	*
Rachel J. Maten	13,160	*		5,264	7,896	*
Ralph J. & Linda D. Scherer	6,576	*		2,630	3,946	*

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Beneficial Owner(a)	Shares Beneficially Owned Prior to Offering			Shares Offered	Shares Beneficially Owned After Offering
	Number	Percentage			Number	Percentage
Rexguard, LLC(k)	526,065	2.39	%	210,426	315,639	1.01	%
Robert E. Poole, Jr.	13,152	*		5,261	7,891	*
Robert E. & Rosalie Collins	6,576	*		2,630	3,946	*
Robert Graham & Lori Ann Luther	39,473	*		15,789	23,684	*
Robert M. & Jayne R. Connelly	6,576	*		2,630	3,946	*
Ronald W. & Patricia A. Lippe	13,425	*		5,370	8,055	*
S & A Family, L.P.	13,425	*		5,370	8,055	*
S & C Partners, L.P.	13,425	*		5,370	8,055	*
Sarah E. Shaner	13,152	*		3,288	9,864	*
SC&J Limited Partnership	39,463	*		15,785	23,678	*
Shaner & Hulburt Capital Partners Limited Partnership(l)	314,588	1.43	%	125,835	188,753	*
SPPC Holdings, LLC Retirement Plan	13,425	*		5,370	8,055	*
Carole Whyte Trust	6,576	*		2,630	3,946	*
The Cohen & Feeley Profit Sharing Trust	6,576	*		1,973	4,603	*
The Edward J. Walsh Living Trust	5,665	*		1,416	4,249	*
The Elizabeth C. Hock Trust	6,576	*		2,630	3,946	*
George H. K. Schenck Revocable Trust dated 9/20/95	6,576	*		2,630	3,946	*
Gretchen M. Binegar Revocable Trust	6,576	*		2,630	3,946	*
Jane Zimmerman Living Trust	46,061	*		18,424	27,637	*
The Jay E. Price Revocable Trust	6,576	*		2,630	3,946	*
The Jeffrey P. Parker Family Remainder Unitrust	131,516	*		52,606	78,910	*
The John L. McDowel III Qtip Trust f/b/o Susan W. McDowell(m)	263,032	1.20	%	105,213	157,819	*
The Lance T. Shaner Irrevocable Grandchildren’s Trust II	101,978	*		25,495	76,483	*
Mary Sue Lawhead Revocable Trust	6,576	*		2,630	3,946	*
The Roberta C. Walsh Living Trust	5,665	*		1,416	4,249	*
The Rose P. Schroeder Revocable Family Trust	6,576	*		2,630	3,946	*
The Roy E. Hock Revocable Trust	6,576	*		2,630	3,946	*
Thomas B. & Grace Tate	6,576	*		2,630	3,946	*
TMT Holdings, LLC Retirement Plan	13,425	*		5,370	8,055	*
TooPG Family Investment Limited Partnership	26,312	*		6,578	19,734	*
Transitown Plaza Associates LLC	65,758	*		16,440	49,319	*
Tremont, L.P.	13,425	*		5,370	8,055	*
Robert Zimmerman Living Trust	19,727	*		7,891	11,836	*
Voora Associates, L.P.	13,425	*		5,370	8,055	*
W. Douglas Gouge(n)	713,029	3.24	%	7,044	705,985	2.26	%
William A. & Honora F. Jaffe	13,152	*		5,261	7,891	*
William A. Jaffe	13,160	*		5,264	7,896	*
William John Lewis	6,576	*		2,630	3,946	*
	25,829,908			5,470,000	20,359,908

* Less than 1%.

(a) Addresses are only given for holders of more than 5% of outstanding common stock who are not executive officers or directors.

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(b) Includes 1,464,871 shares owned by Shaner Family Partner Limited Partnership for which Mr. Shaner disclaims beneficial ownership, includes 526,065 shares owned by Rexguard, LLC for which Mr. Shaner disclaims beneficial ownership, includes 314,588 shares owned by Shaner & Hulburt Capital Partners Limited Partnership for which Mr. Shaner disclaims beneficial ownership, includes 101,978 shares owned by The Lance T. Shaner Irrevocable Grandchildren’s Trust II for which Mr. Shaner disclaims beneficial ownership.

(c) Includes 1,841 shares held in an individual retirement account.

(d) Includes 695,418 shares owned by Douglas Oil & Gas, Inc. for which Mr. Shields disclaims beneficial ownership.

(e) Includes 4,866 shares held in an individual retirement account.

(f) Based upon information provided to us by the selling stockholder, the power to vote or to dispose of the securities offered for resale by The Parker Family Partnership is held by its general partner, Private Equity Investments, LLC, a Florida limited liability company. Based upon information provided to us by the selling stockholder, the manager of Private Equity Investments, LLC is Jeffrey P. Parker.

(g) Thomas F. Shields and W. Douglas Gouge together hold the power to vote or to dispose of the securities offered for resale by Douglas Oil & Gas, Inc. by virtue of their ownership of all of the outstanding voting common stock of the corporation.

(h) Mr. J. Todd Shields is a partner of the law firm of Fulbright & Jaworski, L.L.P. Fulbright & Jaworski will pass upon the validity of the issuance of the shares of common stock to be sold by us in this offering.

(i) Includes 394,636 shares owned by The Parker Family Limited Partnership for which Mr. Parker disclaims beneficial ownership. Includes 131,516 shares owned by The Jeffrey P. Parker Remainder Unitrust for which Mr. Parker disclaims beneficial ownership. Includes 41,324 shares held in an individual retirement account.

(j) Beginning on the date of their respective formations and until April 2005, Mr. Peter Hulburt served as the Secretary of Douglas Oil & Gas, Douglas Westmoreland, Rex Royalties, Midland, PennTex Illinois, PennTex Resources, Rex I and Rex Operating. Mr. Hulburt is the father of Benjamin W. Hulburt and Christopher K. Hulburt.

(k) Mr. Shaner holds the power to vote or to dispose of the securities offered for resale by Rexguard, LLC by virtue of his control of Shaner & Hulburt Capital Partners Limited Partnership, the sole member of Rexguard, LLC.

(l) Mr. Shaner holds the power to vote or to dispose of the securities offered for resale by Shaner & Hulburt Capital Partners Limited Partnership by virtue of his control of its general partner, Shaner Hulburt Capital, Inc.

(m) Based on information provided to us by the selling stockholder, the power to vote or to dispose of the securities offered for resale by The John L. McDowell III QTIP Trust is held by its trustee, Susan W. McDowell.

(n) Includes 695,418 shares owned by Douglas Oil & Gas, Inc. for which Mr. Gouge disclaims beneficial ownership. From the dates of their respective formations until his retirement in March 2006, Mr. Gouge served as the President of Douglas Oil & Gas, Douglas Westmoreland, Midland and Rex Royalties. From its incorporation until his retirement in March 2006, Mr. Gouge served as the Vice President of Business Development of Rex Operating.

In connection with the Reorganization Transactions, we have entered into a registration rights agreement with the Selling Stockholders which grants them the right to sell in this offering a portion of our common stock they will receive in exchange for their equity interests in the Founding Companies. The Selling Stockholders will sell an aggregate of 5,470,000 shares of our common stock in connection with the offering. We will not receive any proceeds from the sale of shares by the Selling Stockholders. Immediately prior to this offering, the Selling Stockholders will own 21,994,702 shares of our common stock. After this offering, the Selling Stockholders will own shares of our common stock, which will represent approximately 53% of our outstanding shares based upon 31,194,702 shares of common stock to be outstanding immediately after completion of this offering.

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The shares retained by the Selling Stockholders after completion of this offering will be subject to lock-up for a period of 180 days from the date of this prospectus (this period may be extended up to 30 additional days by the underwriter if we issue or propose to issue an earnings or other public release or if a material event occurs with respect to us within 15 days of the expiration of the lock-up period or is expected to occur less than 15 days after the expiration of the lock-up period). The registration rights agreement provides that, after the expiration of this lock-up period, if we decide at any time to file a registration statement with the SEC with respect to any offering of our common stock (subject to certain exceptions as further set forth in the registration rights agreement), we will offer the Selling Stockholders the opportunity to register a portion or all of their remaining common stock in such offering, subject to certain priority rights in favor of us (as further set forth in the registration rights agreement).

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RELATED PARTY TRANSACTIONS, CONFLICTS OF INTEREST AND

CERTAIN RELATIONSHIPS

Following the consummation of the Reorganization Transactions, we will continue to lease an office building consisting of approximately 5,270 square feet of office space from Shaner Brothers, LLC, a Pennsylvania limited liability company (“Shaner Brothers”), which is owned by Mr. Shaner and Shaner Family Partners Limited Partnership, a Pennsylvania limited partnership controlled by Mr. Shaner. This office space, which we currently use as our headquarters, is located at 1975 Waddle Road, State College, Pennsylvania. We currently lease this office space pursuant to a written lease agreement between Rex Operating and Shaner Brothers effective as of September 1, 2006. The lease agreement provides for an initial term of three years and expires on August 31, 2009. The lease agreement requires the payment of rent in the amount of $7,908 per month, subject to adjustment on each anniversary date of the lease in accordance with the percentage of increase in the Consumer Price Index for the U.S. for Urban Consumers (CPI-U) for the preceding year (the “CPI Adjustment”). The monthly rent is also subject to adjustment in the form of additional monthly rent which is calculated annually and equal to the percentage of increase of Shaner Brothers’ costs for taxes, insurance premiums and operating expenses for the previous year (the “Additional Monthly Rent”). The annual monthly rent adjustment resulting from the CPI Adjustment and Additional Monthly Rent may not in the aggregate exceed a three percent increase over the prior lease year. Under the terms of the lease, we are responsible for certain costs relating to the interior construction of the building and the payment of all utilities, cleaning expenses, maintenance and other related costs and expenses of the building resulting from our operation, use and occupancy of the premises. Following the expiration of the initial term, we may renew the lease for up to three one-year extensions upon written notice to Shaner Brothers at least 120 days, but no more than six months, prior to the expiration of the current term. We believe the terms of this lease are comparable to terms that could be obtained at an arms’ length basis in the State College, Pennsylvania area for leases of similar office space.

On September 1, 2006, Shaner Brothers loaned $264,656 to Rex Operating to fund its expenses relating to the construction of the interior portions of its headquarters office building. This loan is evidenced by an unsecured promissory note dated September 1, 2006. The promissory note provides for the payment of interest on the unpaid principal sum at a rate of 7% per annum. The loan must be repaid in 60 consecutive equal monthly installments of principal and interest in the amount of $5,240.50. The promissory note matures on September 1, 2011, but may be prepaid in whole or in part at anytime, without premium or penalty. As of December 31, 2006, the outstanding principal amount of the loan was $253,501. We believe that the terms of this loan are comparable to terms that could be obtained at an arms’ length basis from unrelated lenders. We expect that all outstanding amounts under this loan will be repaid in full upon the consummation of the Reorganization Transactions.

From October 2004 until April 2007, we received certain administrative services (such as information technology, human resources, benefit plan administration, payroll and tax services) from Shaner Solutions Limited Partnership, a Delaware limited partnership controlled by Mr. Shaner (“Shaner Solutions”), pursuant to an oral month-to-month agreement providing for a monthly fee of $15,000, plus reimbursement for reasonable out-of-pocket expenses. On April 10, 2007, we terminated our oral month-to-month administrative services agreement with Shaner Solutions. For the years ended December 31, 2006, 2005 and 2004, we paid $180,000, $195,350 and $159,000, respectively, to Shaner Solutions in relation to these services. We believe that the amounts charged by Shaner Solutions were comparable to rates obtainable at an arm’s-length basis in the State College, Pennsylvania area for similar services.

In conjunction with the termination of our oral agreement with Shaner Solutions, we entered into an IT Consultation and Support Services Agreement, a Service Provider Agreement and a Tax Return Engagement Letter Agreement with Shaner Hotel Group Limited Partnership, a Delaware limited partnership controlled by Lance T. Shaner (“Shaner Hotel”). Pursuant to the IT Consultation and Support Services Agreement, Shaner Hotel agreed to provide us with telecommunication, computer system and network administration, and information technology consultation services. Fees for the services provided under this agreement range from $55.00 to $125.00 per hour based upon the type and level of service provided, plus reimbursement for reasonable

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out-of-pocket expenses. The agreement continues until it is terminated by either party upon 90 days advance written notice. Pursuant to the Service Provider Agreement, Shaner Hotel agreed to provide us with certain clerical and administrative support services in connection with the management and administration of our 401(k) retirement plan, payroll and employee health and welfare benefit plans. Under the agreement, we pay a fee of $95.00 per hour for any services performed by Shaner Hotel’s benefits manager and a fee of $55.00 per hour for services provided by other members of Shaner Hotel’s benefits department, plus reimbursement for reasonable out-of-pocket expenses. The term of the Service Provider Agreement is one year, however, either party may terminate the agreement upon 90 days advance written notice. Pursuant to the Tax Return Engagement Letter Agreement, Shaner Hotel agreed to provide us with certain tax planning and tax return preparation services. Fees for the services provided under this agreement range from $100.00 to $155.00 per hour based upon the tax expertise of the particular service provider, plus reimbursement for reasonable out-of-pocket expenses. The agreement continues until it is terminated by either party upon 90 days advance written notice. Since April 10, 2007, we paid $19,376 to Shaner Hotels in relation to these services and anticipate paying a total of approximately $170,000 in 2007. We believe that the amounts charged by Shaner Hotel are comparable to rates obtainable at an arm’s-length basis in the State College, Pennsylvania area for similar services.

We currently have an oral month-to-month agreement with Charlie Brown Air Corp., a New York corporation owned by Mr. Shaner (“Charlie Brown”), regarding the use of two airplanes owned by Charlie Brown. Under our agreement with Charlie Brown, we pay a monthly fee for the right to use the airplanes equal to our percentage (based upon the total number of hours of use of the airplanes by us) of the monthly fixed costs for the airplanes, plus a variable per hour flight rate of $1,350 per hour. The total monthly fixed costs for the airplane is currently approximately $26,000 per month. We believe the terms of this agreement are comparable to terms that could be obtained at an arms’ length basis in the State College, Pennsylvania area for similar private aircraft services.

On June 21, 2007, we obtained a 24.75% limited partnership interest in Charlie Brown II Limited Partnership, a Delaware limited partnership (“Charlie Brown II”), and a 25% membership interest in its general partner, L&B Air LLC, a Delaware limited liability company (“L&B Air”). Charlie Brown II has ordered and agreed to purchase a 500 Eclipse Airplane for approximately $1,700,000. The airplane is scheduled to be delivered from the manufacturer to Charlie Brown II in January of 2008. Shaner Hotel Group Limited Partnership, a Delaware limited partnership controlled by Mr. Shaner (“Shaner Hotel Group”), owns a 24.65% limited partnership interest in Charlie Brown II and a 25% membership interest in L&B Air, and Charlie Brown, an entity owned and controlled by Mr. Shaner, owns a .1% membership interest in Charlie Brown II. The remaining 49.50% limited partnership interest in Charlie Brown II and 50% interest in L&B Air is owned by an unrelated third party. On June 21, 2007, we made capital contributions to Charlie Brown II and L&B Air in the amount of $49,500 and $500, respectively. To fund these capital contributions, we borrowed $50,000 from our Chairman, Lance T. Shaner. This loan is evidenced by a promissory note dated June 21, 2007 and bears interest at the rate of 7% per annum. The promissory note is payable upon the demand of Mr. Shaner and may be prepaid in whole or in part without penalty. We believe that the terms of this loan are comparable to terms that could be obtained at an arms’ length basis from unrelated lenders. We expect that the outstanding principal amount of this loan will be repaid in full after the completion of this offering.

On June 21, 2007, Charlie Brown II and Charlie Brown entered into a First Amended and Restated Aircraft Joint Ownership and Management Agreement. Pursuant to this agreement, Charlie Brown agreed to provide certain aircraft management services, such as routine and scheduled maintenance, flight crew training, cleaning, inspections and flight operations and scheduling of the aircraft. In addition, Charlie Brown agreed to provide a flight crew for the operating of the aircraft and storage space in its hanger for storage of the aircraft. In exchange for these services, Charlie Brown II agreed to pay its proportionate share of Charlie Brown’s fixed costs, including crew, hanger and insurance costs, and a per hour flight charge to be determined by Charlie Brown consistent with current local market rates charged by similar flight operation companies.

The business affairs of Charlie Brown II are managed by its general partner, L&B Air. L&B Air is managed by three managers, appointed by each of its three members. We have designated Benjamin W. Hulburt, our Chief

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Executive Officer, as the manager representing our membership interest. Actions of L&B Air must be approved by a majority of the interest percentages of the managers. Each manager votes in matters before the company in accordance the membership interest percentage of the member that appointed the manager. Certain events, such as the sale by a member of its interest, the merger or consolidation of L&B Air or Charlie Brown II, the filing of bankruptcy, or the sale of the airplane owned by Charlie Brown II, require the consent of all managers. The consent of all limited partners of Charlie Brown II is required before the partnership may change or terminate the management agreement with Charlie Brown, incur any indebtedness, sell substantially all of the partnership’s assets or sell the airplane owned by the partnership. In the event that the limited partners are unable to unanimously agree upon any of these matters within 10 days of the proposal of any such matter, an “impasse” may be declared, and the airplane will be sold by the partnership.

On June 21, 2007, Charlie Brown II borrowed $1,530,000 from Graystone Bank. Proceeds from this loan were used to reimburse Lance T. Shaner and an unrelated third party for a deposit they paid on behalf of Charlie Brown II in connection with the purchase of the 500 Eclipse airplane. The loan matures on June 21, 2017 and bears interest at a rate of LIBOR plus 2.5%. The loan requires payments of interest only for the first three months of the loan. Thereafter, Charlie Brown II is required to make monthly payments of principal and interest utilizing an amortization period of 180 months. The loan to Charlie Brown II was guaranteed by Lance T. Shaner and the unrelated third party.

Following the consummation of the Reorganization Transactions, Mr. Shaner will be our Chairman and a significant stockholder of the Company. Mr. Shaner’s ownership and association with Shaner Brothers, Shaner Solutions, Shaner Hotel, Charlie Brown, Charlie Brown II and us could create a conflict of interest between the interests of those entities and Mr. Shaner’s duties and obligations to us. The compensation for these arrangements and the purchase, leasing, financing, management and other arrangements between us and any Shaner affiliates may not be (to the extent permissible under applicable laws and regulations) a result of arm’s-length negotiations, and the relationships created by virtue of these arrangements may be subject to certain conflicts of interest. Following the consummation of the Reorganization Transactions, our board of directors (with Mr. Shaner abstaining) will perform a quarterly review of these contractual agreements, whether oral or written, and may continue, extend, amend or terminate any of these agreements. We currently do not have a policy regarding the approval of any new related party transactions; however, we expect that shortly after the completion of this offering our board of directors will adopt such a policy. We expect that this policy will provide that any related party transaction for services or property having a value to either party to the contract in excess of $5,000 will require the approval of a majority of our independent directors. The following table shows all payments and fees that we anticipate any member of management or their affiliates will receive under the current contractual arrangements in 2007:

Name of Affiliate	Contractual Relationship	Anticipated     Monthly Amount	Anticipated     Annual Amount
Shaner Brothers	Office Rent	$  7,908	$  94,896
Shaner Brothers	Office Loan	5,241	62,886
Shaner Hotels	Administrative Services	14,451	173,412
Charlie Brown(1)	Charter Flight Services	26,500	318,000
Total		$54,100	$649,194

(1) Assumes 10 hours per month flight usage.

At December 31, 2006, there was a working capital loan payable to Mr. Shaner, our Chairman, in the amount of $1,820,000 from PennTex Illinois, one of the Founding Companies. Mr. Shaner is the sole stockholder of PennTex Illinois. The loan was non-interest-bearing and was payable upon the demand of Mr. Shaner. During the three months ended March 31, 2007, the outstanding amount was satisfied through the conversion of $820,000 into an equity capital contribution into such Founding Company and the repayment of $1,000,000 to Mr. Shaner.

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Substantially all of our outstanding loans are owed by those Founding Companies which are owned primarily by our management and affiliates. These loans are not in current compliance with certain financial covenants in their credit agreements, although, in most cases, waivers of the non-compliance have been obtained from lenders for limited periods. These loans are expected to be retired in full with proceeds from this offering. The retirement of these loans may be viewed as a benefit to members of management who own the borrower Founding Companies. An affiliate of KeyBanc Capital Markets Inc., the lead underwriter for this offering, is the lender under the Rex IV credit facility. As of April 12, 2007, approximately $37 million was outstanding under the facility. These instances of non-compliance include:

As of December 31, 2006, Rex Energy IV was not in compliance with the negative covenant in its credit agreement requiring that its ratio of total debt to EBITDAX, as defined in the credit agreement, not exceed 5.5:1. Rex Energy IV obtained a waiver from its lender of this covenant for the fourth quarter of 2006.

On March 30, 2007, Rex IV and KeyBank National Association, or KeyBank NA, executed the First Amendment to the Credit Agreement, which extends the maturity date to the earlier to occur of (i) the date of closing of our initial public offering and (ii) December 31, 2007. In addition, the First Amendment to the Credit Agreement provides for a change in the interest rate per annum to the LIBOR rate plus 400 basis points. The First Amendment to the Credit Agreement also made the following changes to certain negative covenants: (i) the ratio of total debt to EBITDAX was changed from 5.75:1.00 to 7.00:1.00 for the fiscal quarter ending June 30, 2007, 6.75:1.00 for the fiscal quarter ending September 30, 2007 and 6.50:1.00 for the fiscal quarter ending December 31, 2007; and (ii) the ratio of EBITDAX to interest was changed from 1.75:1.00 to 1.50:1.00.

As of December 31, 2006, PennTex Resources and PennTex Illinois, as co-borrowers, were not in compliance with the negative covenant in their credit agreement requiring that their ratio of current assets to current liabilities, as defined in the credit agreement, be at least 1.1:1. The companies have received a waiver of these covenants for the fourth quarter of 2006 and the first and second quarters of 2007. This credit facility will be repaid in full from the proceeds of this offering.

As of December 31, 2006, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, were not in compliance with the negative covenant in their credit agreement that states that the co-borrowers will not permit their tangible net worth, on a combined basis, as of the end of any fiscal year to be less than the amount that is 15% less than the tangible net worth of the co-borrowers as indicated on their audited year end financial statements as of December 31, 2005; provided, however, that commencing on December 31, 2006, and at the end of each fiscal year thereafter, this amount will increase by $500,000. The companies received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarters of 2007. This credit facility will be repaid in full from the proceeds of this offering.

As of March 31, 2007, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, were not in compliance with the negative covenant in their credit agreement that states that the co-borrowers will maintain a minimum fixed coverage charge, as defined in the credit agreement, of at least 1.25. The companies are in discussions with the lender to obtain a waiver, and the companies have reclassified this debt as current. The credit facility will be repaid in full from the proceeds of this offering.

As of December 31, 2006, Rex Energy III was not in compliance with the negative covenant in its credit agreement requiring that its ratio of total reserve value to total funded debt, as defined in the credit agreement, be at least 2.5:1. Rex Energy III obtained a waiver from its lender of this covenant for the fourth quarter of 2006 and the first quarter and second quarter of 2007. This credit facility will be repaid in full from the proceeds of this offering.

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DESCRIPTION OF CAPITAL STOCK

The following is a summary description of the rights of our common stock and preferred stock and related provisions of our amended and restated certificate of incorporation and bylaws. The following description of our capital stock is intended as a summary only and is qualified in its entirety by reference to our amended and restated certificate of incorporation and by-laws, which are filed as exhibits to the registration statement, of which this prospectus forms a part, and to the applicable provisions of Delaware law.

Common Stock

Our amended and restated certificate of incorporation authorizes 100,000,000 shares of common stock, par value $0.001 per share. Upon the closing of the Reorganization Transactions and this offering, there will be 31,194,702 shares of our common stock outstanding, or 33,395,202 shares if the underwriters exercise their over-allotment option in full.

Voting Rights

Each share of our common stock entitles its holder to one vote on all matters to be voted on by the stockholders. Except for the election of directors, which is determined by a plurality vote, all matters to be voted on by stockholders must be approved by a majority of the votes entitled to be cast by the holders of our common stock present in person or represented by proxy, voting as a single class. Except as otherwise provided by law or in our amended and restated certificate of incorporation, and subject to any voting rights granted to holders of any outstanding preferred stock and the powers of our board of directors to amend our bylaws, amendments to our amended and restated certificate of incorporation and bylaws must be approved by a majority of the votes entitled to be cast by the holders of our common stock, voting as a single class. Holders of our common stock are not entitled to cumulate their votes in the election of directors. Each of our directors will be elected annually by our stockholders voting as a single class.

No Preemptive, Redemption or Conversion Rights

Holders of our common stock are not entitled to preemptive rights and our common stock is not subject to redemption or conversion. There are no redemption or sinking fund provisions applicable to our common stock.

Dividends

Subject to preferences that may apply to shares of preferred stock outstanding at the time, the holders of outstanding shares of our common stock are entitled to receive dividends out of assets legally available at the time if, as and when declared by our board of directors.

Right to Receive Liquidation Distributions

Upon the liquidation, dissolution or winding-up of the Company, the holders of our common stock are entitled to share in all assets remaining after payment of all our debts and other liabilities and the liquidation preferences of any outstanding preferred stock.

Fully Paid

All shares of our common stock outstanding upon completion of the Reorganization Transactions and this offering will be fully paid and nonassessable.

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Preferred Stock

Our amended and restated certificate of incorporation authorizes 100,000 shares of preferred stock, par value $0.001 per share. Our board of directors has the authority, without action by our stockholders, to designate and issue our preferred stock in one or more series and to designate the rights, preferences and privileges of each series, which may be greater than the rights of our common stock. It is not possible to state the actual effect of the issuance of any shares of our preferred stock upon the rights of holders of our common stock until our board of directors determines the specific rights of the holders of our preferred stock. However, the effects might include, among other things, restricting dividends on our common stock, diluting the voting power of our common stock, impairing the liquidation rights of our common stock, or delaying or preventing a change in control of the Company without further action by our stockholders.

Upon completion of Reorganization Transactions and this offering, no shares of our preferred stock will be outstanding, and we have no present plans to issue any shares of preferred stock.

Anti-Takeover Effects of Delaware Law and Our Certificate of Incorporation and Bylaws

Certain provisions of Delaware law, our amended and restated certificate of incorporation and our bylaws contain provisions that could have the effect of delaying, deferring or discouraging another party from acquiring control of the Company. These provisions, which are summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of the Company to first negotiate with our board of directors. We believe that the benefits of increased protection of our potential ability to negotiate with an unfriendly or unsolicited acquirer outweigh the disadvantages of discouraging a proposal to acquire the Company because negotiation of these proposals could result in an improvement of their terms.

Delaware Law

We are subject to the provisions of Section 203 of the Delaware General Corporation Law regulating corporate takeovers. In general, those provisions prohibit a Delaware corporation from engaging in any business combination with any stockholder who owns 15% or more of our outstanding voting stock (as well as affiliates and associates of such stockholders) for a period of three years following the date that the stockholder became an interested stockholder, unless:

• the transaction is approved by the board before the date the interested stockholder acquired the stock;

• upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding those shares owned by various employee benefit plans or persons who are directors and also officers; or

• on or after the date the stockholder acquired the stock, the business combination is approved by the board and authorized at a meeting of stockholders by the affirmative vote of at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

Section 203 defines “business combination” to include the following:

• any merger or consolidation involving the corporation and the interested stockholder;

• any sale, transfer, pledge or other disposition of 10% or more of the assets of the corporation involving the interested stockholder;

• subject to certain exceptions, any transaction that results in the issuance or transfer by the corporation of any stock of the corporation to the interested stockholder;

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• any transaction involving the corporation that has the effect of increasing the proportionate share of the stock of any class or series of the corporation beneficially owned by the interested stockholder; or

• the receipt by the interested stockholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the corporation.

In general, Section 203 defines an interested stockholder as any entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation and any entity or person affiliated with or controlling or controlled by any of these entities or persons.

A Delaware corporation may opt out of this provision either with an express provision in its original certificate of incorporation or in an amendment to its certificate of incorporation or bylaws approved by its stockholders. However, we have not opted out, and do not currently intend to opt out, of this provision. The statute could prohibit or delay mergers or other takeover or change in control attempts and, accordingly, may discourage attempts to acquire the Company.

Charter and Bylaws

In addition, some provisions of our amended and restated certificate of incorporation and bylaws may be deemed to have an anti-takeover effect and may delay, defer or prevent a tender offer or takeover attempt that a stockholder might deem to be in the stockholder’s best interest. The existence of these provisions could limit the price that investors might be willing to pay in the future for shares of our common stock.

Authorized but unissued shares. The authorized but unissued shares of our common stock and preferred stock are available for future issuance without stockholder approval. These additional shares may be used for a variety of corporate purposes, such as for additional public offerings, acquisitions and employee benefit plans. The existence of authorized but unissued and unreserved common stock and preferred stock could render more difficult or discourage an attempt to obtain control of the Company by means of a proxy contest, tender offer, merger or otherwise.

Amendment to bylaws. Our board of directors is authorized to make, alter or repeal our bylaws without further stockholder approval.

Advance notice of director nominations and matters to be acted upon at meetings. Our bylaws contain advance notice requirements for nominations for directors to our board of directors and for proposing matters that can be acted upon by stockholders at stockholder meetings.

No stockholder action without written consent. Our amended and restated certificate of incorporation provides that stockholders may only act at a duly called meeting.

Limitation on Liability and Indemnification Matters

Our amended and restated certificate of incorporation limits the liability of directors to the fullest extent permitted by Delaware law. The effect of these provisions is to eliminate our rights and those of our stockholders, through stockholders’ derivative suits on behalf of the Company, to recover monetary damages against a director for breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior. However, exculpation does not apply if the directors acted in bad faith, knowingly or intentionally violated the law, authorized illegal dividends or redemptions or derived an improper benefit from their actions as directors. In addition, our bylaws provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law.

There is no currently pending material litigation or proceeding involving any of our directors or officers for which indemnification is sought.

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Transfer Agent and Registrar

The transfer agent and registrar for our common stock is ComputerShare Investor Services, LLC.

Listing

We have applied to list our common stock on The Nasdaq Global Market, subject to official notice of issuance, under the symbol “REXX”.

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock. The sale of a substantial amount of our common stock in the public market after this offering, or the perception that such sales may occur, could adversely affect the prevailing market price of our common stock. Furthermore, because some of our shares will not be available for sale shortly after this offering due to the contractual and legal restrictions on resale described below, the sale of a substantial amount of common stock in the public market after these restrictions lapse could adversely affect the prevailing market price of our common stock and our ability to raise equity capital in the future.

Sales of Restricted Securities

Upon the completion of this offering, we will have 31,194,702 shares of common stock outstanding (assuming the underwriters’ over-allotment option to purchase additional shares of common stock is not exercised in full), which includes the approximately 9,200,000 million shares of common stock sold by us in this offering.

Of the shares to be outstanding after the closing of this offering, the 14,670,000 shares sold in this offering will be freely tradable without restriction under the Securities Act, except that any shares purchased in this offering by our “affiliates,” as that term is defined in Rule 144 under the Securities Act of 1933, generally may be sold in the public market only in compliance with Rule 144. The remaining 16,524,702 shares of common stock are “restricted” shares under Rule 144 and therefore generally may be sold in the public market only in compliance with Rule 144. In addition, substantially all of these restricted securities will be subject to the lock-up agreements described below.

Rule 144

In general, under Rule 144 as currently in effect, beginning 90 days after the date of this prospectus, a person or persons whose shares are aggregated, who have beneficially owned restricted shares for at least one year, including persons who may be deemed to be our “affiliates,” would be entitled to sell within any three-month period a number of shares that does not exceed the greater of 1% of the number of shares of common stock then outstanding, which will equal approximately 311,947 shares immediately after this offering, or the average weekly trading volume of our common stock on the Nasdaq Global Market during the four calendar weeks before a notice of the sale on SEC Form 144 is filed.

Sales under Rule 144 are also subject to certain manner of sale provisions and notice requirements and to the availability of certain public information about us.

Rule 144(k)

Under Rule 144(k), a person who is not deemed to have been one of our “affiliates” at any time during the 90 days preceding a sale, and who has beneficially owned the shares proposed to be sold for at least two years, including the holding period of any prior owner other than an “affiliate,” is entitled to sell these shares without complying with the manner of sale, public information, volume limitation or notice provisions of Rule 144.

Stock Issued Under Our Long-Term Incentive Plan

We intend to file a registration statement on Form S-8 under the Securities Act to register an amount up to 10% of the number of shares of common stock outstanding immediately after completion of this offering issuable, with respect to options and restricted stock units to be granted, or otherwise, under our Long-Term Incentive Plan. Currently, there are no outstanding options to purchase shares of our common stock or restricted stock units. This registration statement is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Shares issued upon the exercise of

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stock options or restricted stock units after the effective date of the Form S-8 registration statement will be eligible for resale in the public market without restriction, subject to Rule 144 limitations applicable to affiliates.

Lock-up Agreements

Notwithstanding the foregoing, our directors and officers and the Selling Stockholders have agreed with the underwriters not to dispose of or hedge any of their common stock or securities convertible into or exchangeable for shares of common stock during the period from the date of this prospectus continuing through the date 180 days after the date of this prospectus, except with the prior written consent of the underwriters, subject to certain limitations and limited exceptions. The lock-up period may be extended as further described in “Principal and Selling Stockholders—Selling Stockholders.”

Registration Rights

As described in “Principal and Selling Stockholders—Selling Stockholders,” we have entered into a registration rights agreement with the Selling Stockholders, pursuant to which they may sell a portion of their shares of common stock in this offering and may participate in future registrations of securities by us. We do not have any other contractual obligations to register our stock.

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MATERIAL U.S. FEDERAL TAX CONSIDERATIONS FOR NON-U.S. HOLDERS OF COMMON STOCK

The following discussion summarizes the material U.S. federal income and estate tax consequences of the purchase, ownership and disposition of our common stock by certain non-U.S. holders (as defined below). This discussion only applies to non-U.S. holders who purchase and hold our common stock as a capital asset for U.S. federal income tax purposes (generally property held for investment). This discussion does not describe all of the tax consequences that may be relevant to a non-U.S. holder in light of its particular circumstances.

For purposes of this discussion, a “non-U.S. holder” means a person (other than a partnership) that is not for U.S. federal income tax purposes any of the following:

• an individual citizen or resident of the United States (including certain former citizens and former long-term residents);

• a corporation (or any other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

• an estate the income of which is subject to U.S. federal income taxation regardless of its source; or

• a trust if it (a) is subject to the primary supervision of a court within the United States and one or more United States persons have the authority to control all substantial decisions of the trust or (b) has a valid election in effect under applicable United States Treasury regulations to be treated as a United States person.

This discussion is based upon provisions of the Internal Revenue Code of 1986, as amended, or the “Code,” and Treasury regulations, rulings and judicial decisions as of the date hereof. These authorities may be changed, perhaps retroactively, so as to result in U.S. federal income and estate tax consequences different from those summarized below. This discussion does not address all aspects of U.S. federal income and estate taxes and does not describe any foreign, state, local or other tax considerations that may be relevant to non-U.S. holders in light of their particular circumstances. In addition, this discussion does not describe the U.S. federal income and estate tax consequences applicable to you if you are subject to special treatment under the U.S. federal income tax laws (including if you are a United States expatriate, “controlled foreign corporation,” “passive foreign investment company,” corporation that accumulates earnings to avoid U.S. federal income tax, pass-through entity or an investor in a pass-through entity). We cannot assure you that a change in law will not alter significantly the tax considerations that we describe in this discussion.

If a partnership (or any other entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the U.S. federal income tax treatment of a partner of that partnership will generally depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership holding our common stock, you should consult your tax advisors.

THIS DISCUSSION IS PROVIDED FOR GENERAL INFORMATION ONLY AND DOES NOT CONSTITUTE LEGAL ADVICE TO ANY PROSPECTIVE PURCHASER OF OUR COMMON STOCK. ADDITIONALLY, THIS DISCUSSION CANNOT BE USED BY ANY HOLDER FOR THE PURPOSE OF AVOIDING TAX PENALTIES THAT MAY BE IMPOSED ON SUCH HOLDER. IF YOU ARE CONSIDERING THE PURCHASE OF OUR COMMON STOCK, YOU SHOULD CONSULT YOUR OWN TAX ADVISORS CONCERNING THE U.S. FEDERAL INCOME AND ESTATE TAX CONSEQUENCES OF PURCHASING, OWNING AND DISPOSING OF OUR COMMON STOCK IN LIGHT OF YOUR PARTICULAR CIRCUMSTANCES AND ANY CONSEQUENCES ARISING UNDER THE LAWS OF APPLICABLE STATE, LOCAL OR FOREIGN TAXING JURISDICTIONS. YOU SHOULD ALSO CONSULT WITH YOUR TAX ADVISORS CONCERNING ANY POSSIBLE ENACTMENT OF LEGISLATION THAT WOULD AFFECT YOUR INVESTMENT IN OUR COMMON STOCK IN YOUR PARTICULAR CIRCUMSTANCES.

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Distributions on common stock

In general, if distributions are made with respect to our common stock, such distributions will be treated as dividends to the extent of our current and accumulated earnings and profits as determined under the Code and be subject to withholding as discussed below. Any portion of a distribution that exceeds our current and accumulated earnings and profits will first be applied to reduce the non-U.S. holder’s basis in the common stock and, to the extent such portion exceeds the non-U.S. holder’s basis, the excess will be treated as gain from the disposition of the common stock, the tax treatment of which is discussed below under “Dispositions of common stock.” In addition, if we are a U.S. real property holding corporation, or a “USRPHC”, which we expect we will be, and any distribution exceeds our current and accumulated earnings and profits, we will need to choose to satisfy our withholding requirements either by treating the entire distribution as a dividend, subject to the withholding rules in the following paragraph (and withhold at a minimum rate of 10%), or by treating only the amount of the distribution equal to our reasonable estimate of our current and accumulated earnings and profits as a dividend, with the excess portion of the distribution subject to withholding as if such excess were the result of a sale of shares in a USRPHC (discussed below under “Dispositions of common stock”).

Dividends paid to a non-U.S. holder of our common stock generally will be subject to withholding of U.S. federal income tax at a 30% rate or such lower rate as may be specified by an applicable income tax treaty. However, dividends that are effectively connected with the conduct of a trade or business by the non-U.S. holder within the United States (and, where a tax treaty applies, are attributable to a U.S. permanent establishment of the non-U.S. holder) are not subject to the withholding tax, provided certain certification and disclosure requirements are satisfied. Instead, such dividends are subject to U.S. federal income tax on a net income basis in the same manner as if the non-U.S. holder were a United States person as defined under the Code, unless an applicable income tax treaty provides otherwise. Any such effectively connected dividends received by a foreign corporation may be subject to an additional “branch profits tax” at a 30% rate or such lower rate as may be specified by an applicable income tax treaty.

A non-U.S. holder of our common stock who wishes to claim the benefit of an applicable treaty rate and avoid backup withholding, as discussed below, for dividends will be required to (a) complete Internal Revenue Service Form W-8BEN (or other applicable form) and certify under penalty of perjury that such holder is not a United States person as defined under the Code and is eligible for treaty benefits or (b) if our common stock is held through certain foreign intermediaries, satisfy the relevant certification requirements of applicable Treasury regulations. Special certification and other requirements apply to certain non-U.S. holders that are pass-through entities rather than corporations or individuals.

A non-U.S. holder of our common stock eligible for a reduced rate of U.S. withholding tax pursuant to an income tax treaty may obtain a refund of any excess amounts withheld by filing an appropriate claim for refund with the Internal Revenue Service.

Disposition of common stock

Any gain realized by a non-U.S. holder on the disposition of our common stock generally will not be subject to U.S. federal income or withholding tax unless:

• the gain is effectively connected with a trade or business of the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a U.S. permanent establishment of the non-U.S. holder);

• the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of that disposition, and certain other conditions are met; or

• we are or have been a USRPHC for U.S. federal income tax purposes, as such term is defined in Section 897(c) of the Code, and you owned directly or pursuant to attribution rules at any time during the five year period ending on the date of disposition more than 5% of our common stock. This

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assumes that our common stock is regularly traded on an established securities market, within the meaning of Section 897(c)(3) of the Code. We believe we will be a USRPHC and that our common stock will be treated as being traded on an established securities market.

An non-U.S. holder described in the first bullet point immediately above will be subject to tax on the net gain derived from the sale under regular graduated U.S. federal income tax rates, and if it is a corporation, may be subject to the branch profits tax equal to 30% of its effectively connected earnings and profits or at such lower rate as may be specified by an applicable income tax treaty. An individual non-U.S. holder described in the second bullet point immediately above will be subject to a flat 30% tax on the gain derived from the sale, which may be offset by U.S. source capital losses, even though the individual is not considered a resident of the United States. A non-U.S. holder described in the third bullet point above will be subject to U.S. federal income tax under regular graduated U.S. federal income tax rates with respect to the gain recognized.

U.S. federal estate tax

Our common stock beneficially owned by an individual who is not a citizen or resident of the United States (as defined for U.S. federal estate tax purposes) at the time of death will generally be includable in the decedent’s gross estate for U.S. federal estate tax purposes, unless an applicable treaty provides otherwise.

Information reporting and backup withholding

We must report annually to the Internal Revenue Service and to each non-U.S. holder the amount of dividends paid to such non-U.S. holder and the tax withheld with respect to such dividends, regardless of whether withholding was required. Copies of the information returns reporting such dividends and withholding may also be made available to the tax authorities in the country in which the non-U.S. holder resides under the provisions of an applicable income tax treaty.

A non-U.S. holder will be subject to backup withholding for dividends paid to such non-U.S. holder unless such non-U.S. holder certifies under penalty of perjury that it is a non-U.S. holder (and the payor does not have actual knowledge or reason to know that such non-U.S. holder is a United States person as defined under the Code), and such non-U.S. holder otherwise establishes an exemption.

Information reporting and, depending on the circumstances, backup withholding will apply to the proceeds of a sale of our common stock within the United States or conducted through certain United States-related financial intermediaries, unless the beneficial owner certifies under penalty of perjury that it is a non-U.S. holder (and the payor does not have actual knowledge or reason to know that the beneficial owner is a United States person as defined under the Code), and such owner otherwise establishes an exemption.

Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a non-U.S. holder’s U.S. federal income tax liability provided the required information is furnished to the Internal Revenue Service.

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UNDERWRITING

Subject to the terms and conditions set forth in an underwriting agreement by and between KeyBanc Capital Markets Inc., as representative for the underwriters named in the agreement, we and the selling stockholders have agreed to sell each underwriter, and each underwriter has severally agreed to purchase from us and the selling stockholders, the number of common stock shares set forth opposite its name in the table below:

Underwriter	Number of Shares
KeyBanc Capital Markets Inc.
RBC Capital Markets Corporation
A.G. Edwards & Sons, Inc.
Johnson Rice & Company L.L.C.
Pickering Energy Partners, Inc.
Total

Under the terms of the underwriting agreement, the underwriters are committed to purchase all of these shares if any shares are purchased. If an underwriter defaults, the underwriting agreement provides that the purchase commitments of the nondefaulting underwriters may be increased or the underwriting agreement may be terminated.

We and the selling stockholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

The underwriting agreement provides that the underwriters’ obligations to purchase the common stock depends on the satisfaction of the conditions contained in the underwriting agreement. The conditions contained in the underwriting agreement include the requirement that the representations and warranties made by us and the selling stockholders to the underwriters are true, that there is no material change in the financial markets and that we deliver to the underwriters customary closing documents.

The underwriters propose to offer the shares of common stock directly to the public at $             per share and to certain dealers at such price less a concession not in excess of $             per share. The underwriters may allow, and such dealers may reallow, a concession not in excess of $              per share to other dealers. If all of the shares are not sold at the public offering price, the representatives of the underwriters may change the public offering price and the other selling terms.

We intend to distribute and deliver this prospectus by hand or by mail only and not by electronic delivery. Also, we intend to use printed prospectuses only and not other forms of prospectuses.

We and the selling stockholders have granted the underwriters an option to purchase up to 2,200,500 additional shares from us at the public offering price less the underwriting discount. The underwriters may exercise the option for 30 days from the date of this prospectus solely to cover any over-allotments. If the underwriters exercise this option, each will be obligated, subject to conditions contained in the underwriting agreement, to purchase a number of additional common shares proportionate to that underwriter’s initial amount reflected in the above table.

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The following table shows the per share and total underwriting discount that we and the selling stockholders will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares.

	Per Share	Total Without Option Exercised	Total With Option Exercised
Public offering price
Underwriting discount payable by us
Underwriting discount payable by selling stockholders
Proceeds (before expenses) to us
Proceeds (before expenses) to the selling stockholders

We estimate that the total expenses related to this offering payable by us, excluding underwriting discounts and commissions, will be approximately $2.3 million. Of this amount, we have paid approximately $968,000 as of May 31, 2007 and expect to incur additional offering expenses of approximately $1.3 million.

In addition, we will pay KeyBanc Capital Markets Inc. an aggregate structuring fee equal to 0.5% of the gross proceeds of this offering, including proceeds from any exercise of the underwriters’ over-allotment option as described below, in consideration of advice rendered by KeyBanc Capital Markets Inc. regarding the structure of this offering and Rex Energy Corporation.

We, our executive officers and directors and substantially all of our stockholders have agreed with the underwriters, for a period of 180 days after the date of this prospectus, subject to certain exceptions, not to offer, sell, hedge or otherwise dispose of any common shares or any securities convertible into or exchangeable for common stock, without the prior written consent of KeyBanc Capital Markets Inc. Upon completion of the Reorganization Transactions, 21,994,702 shares of common stock (including shares underlying options exercisable within 60 days) were beneficially owned by our executive officers and directors and such stockholders. However, KeyBanc Capital Markets Inc. may, in its sole discretion and at any time without notice, release all or any portion of the securities subject to these lock-up agreements. KeyBanc Capital Markets Inc. has no present intent or arrangement to release any of the securities subject to these lock-up agreements. Factors in deciding whether to release these securities may include the length of time before the particular lock-up expires, the number of shares involved, historical trading volumes, the reason for the requested release, market conditions and whether the person seeking the release is our officer, director or affiliate.

The 180-day restricted period described in the preceding paragraph will be extended if:

• during the last 17 days of the 180-day restricted period we issue an earnings release or announce material news or a material event; or

• prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or event.

Until the distribution of common shares is completed, SEC rules may limit the underwriters from bidding for and purchasing our common stock. However, the underwriters may engage in transactions that stabilize the price of the common shares, such as bids or purchases of shares in the open market while this offering is in progress to peg, fix, or maintain that price. These transactions also may include short sales and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in this offering. “Covered” short sales are sales made in an amount not

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greater than the underwriters’ option to purchase additional shares from us. The underwriters may reduce that short position by purchasing shares in the open market or by exercising all or part of the over-allotment option described above. In determining the source of shares to close out the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase additional shares pursuant to the option granted to them. “Naked” short sales are any sales in excess of such option. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common shares in the open market after pricing that could adversely affect investors who purchase in this offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representative has repurchased shares sold by or for the account of such underwriter in stabilizing or short covering transactions.

Neither we nor the underwriters make any representation or prediction as to the effect the transactions described above may have on the price of the common stock. Any of these activities may have the effect of preventing or retarding a decline in the market price of our common stock. They may also cause the price of our common stock to be higher than the price that would otherwise exist on the open market in the absence of these transactions. The underwriters may conduct these transactions on the NASDAQ Global Market or in the over-the-counter market, or otherwise. If the underwriters commence any of these transactions, they may discontinue them without notice at any time.

KeyBanc Capital Markets Inc. has investment discretion over accounts which may include shares of our common stock. In addition, some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other transactions with us and perform services for us in the ordinary course of their business. They have received customary fees and commissions for those transactions. In the course of their businesses, the underwriters and their affiliates may actively trade our securities or loans for their own account or for the accounts of customers, and, accordingly, the underwriters and their affiliates may at any time hold long or short positions in such securities or loans.

There is no established trading market for the shares. The offering price for the shares has been determined by us and the underwriters, based on the following factors:

• the history and prospects for the industry in which we compete;

• our past and present operations;

• our historical results of operations;

• our prospects for future business and earning potential;

• our management;

• the general condition of the securities markets at the time of this offering;

• the recent market prices of securities of generally comparable companies;

• the market capitalization and stages of development of other companies which we and the underwriters believe to be comparable to us; and

• other factors deemed to be relevant.

Certain of the underwriters and their affiliates have performed investment banking, commercial banking and advisory services for us and our affiliates for which they have received customary fees and expenses. The underwriters and their affiliates may in the future perform investment banking and advisory services for us and our affiliates from time to time for which they may in the future receive customary fees and expenses. An affiliate of KeyBanc Capital Markets Inc. is the lender under Rex IV’s credit facility and has committed to serve as the administrative agent under our proposed $75 million senior credit facility.

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Because an affiliate of KeyBanc Capital Markets Inc. is expected to be a lender under our proposed $75 million senior credit facility, is a lender under Rex IV’s existing credit facility and will receive more than 10% of the net proceeds of this offering when we repay Rex IV’s credit facility, KeyBanc Capital Markets Inc. may be deemed to have a “conflict of interest” with us under Rule 2710(h)(1) of the National Association of Securities Dealers, Inc., or the NASD. When a NASD member with a conflict of interest participates as an underwriter in a public offering, that rule requires that the initial public offering price be no higher than that recommended by a “qualified independent underwriter,” as defined by the NASD. In accordance with this rule, RBC Capital Markets Corporation has assumed the responsibilities of acting as a qualified independent underwriter. In its role as qualified independent underwriter, RBC Capital Markets Corporation has performed a due diligence investigation and participated in the preparation of this prospectus and the registration statement of which this prospectus is a part. RBC Capital Markets Corporation will not receive any additional fees for serving as qualified independent underwriter in connection with this offering. We have agreed to indemnify RBC Capital Markets Corporation against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act.

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LEGAL MATTERS

The validity of the issuance of the shares of common stock to be sold in this offering will be passed upon for us by Fulbright & Jaworski L.L.P., Houston, Texas. J. Todd Shields, a partner of Fulbright & Jaworski L.L.P., owns a 0.83% limited partner interest in Rex II. Vinson & Elkins L.L.P., Houston, Texas, will act as counsel to the underwriters.

EXPERTS

The combined financial statements of the Founding Companies of Rex Energy Corporation as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006, the individual financial statements of the Founding Companies listed below, and the statements of revenues and direct operating expenses listed below, have been audited by Malin, Bergquist & Company, LLP, an independent registered public accounting firm, as indicated in their accompanying report, and included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Founding Companies individual financial statements:

• Consolidated Douglas Oil & Gas Limited Partnership as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006;

• Douglas Westmoreland Limited Partnership as of December 31, 2006 and 2005, and for the years then ended and for the period from inception to December 31, 2004;

• Midland Exploration Limited Partnership as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006;

• PennTex Resources, L.P. as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006;

• Rex Energy II Limited Partnership as of December 31, 2006 and 2005, and for the years then ended and for the period from inception to December 31, 2004;

• Rex Energy III LLC as of December 31, 2006 and for the period from inception to December 31, 2006;

• Rex Energy IV, LLC as of December 31, 2006 and for the period from inception to December 31, 2006;

• Rex Energy Operating Corp. as of December 31, 2006 and 2005 and for the years then ended;

• Rex Energy Royalties Limited Partnership as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006;

• Rex Energy II Alpha Limited Partnership as of December 31, 2006 and 2005, and for the year ended December 31, 2006 and the period from inception to December 31, 2005;

• PennTex Resources Illinois, Inc. as of December 31, 2006 and 2005, and for the years then ended; and

• New Albany-Indiana, LLC (a development company) as of December 31, 2006 and 2005, and for the year ended December 31, 2006 and the period from inception to December 31, 2005.

Statements of revenues and direct operating expenses:

• Oil property acquired from ERG Illinois, Inc. for the period March 1, 2004 through December 31, 2004;

• Oil property acquired from Hux Oil Corp. and Pioneer Oil Company, Inc. for the period January 1, 2005 through November 30, 2005 and the year ended December 31, 2004;

138

• Oil property acquired from National Energy Corporation for the period January 1, 2005 through June 30, 2005 and the year ended December 31, 2004;

• Oil property acquired from Team Energy, L.L.C. for the period January 1, 2006 through May 31, 2006 and the years ended December 31, 2005 and 2004;

• Team Energy non-operated oil property acquired for the period January 1, 2006 through May 31, 2006 and the years ended December 31, 2005 and 2004; and

• Oil property acquired from Tsar Energy II, L.L.C. for the period January 1, 2006 through September 30, 2006, the year ended December 31, 2005, and the period March 1, 2004 through December 31, 2004.

The information included in this prospectus as of December 31, 2006 and 2005 relating to our estimated quantities of proved reserves is derived from reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, as stated in their respective reserve reports with respect thereto. This information is included in this prospectus in reliance upon the authority of said firm as experts with respect to the matters covered by their report and the giving of their report.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the issuance of shares of our common stock being offered hereby. This prospectus, which forms a part of the registration statement, does not contain all of the information set forth in the registration statement. For further information with respect to us and the shares of our common stock, reference is made to the registration statement. Statements contained in this prospectus as to the contents of any contract or other document are not necessarily complete. We are not currently subject to the informational requirements of the Securities Exchange Act of 1934. As a result of the offering of the shares of our common stock, we will become subject to the informational requirements of the Exchange Act and, in accordance therewith, will file reports and other information with the SEC. The registration statement, such reports and other information can be inspected and copied at the Public Reference Room of the SEC located at 100 F Street, N.E., Washington, D.C. 20549. Copies of such materials, including copies of all or any portion of the registration statement, can be obtained from the Public Reference Room of the SEC at prescribed rates. You can call the SEC at 1-800-SEC-0330 to obtain information on the operation of the Public Reference Room. Such materials may also be accessed electronically by means of the SEC’s website at www.sec.gov.

139

INDEX TO FINANCIAL STATEMENTS

	Page
Interim Financial Statements of Rex Energy Corporation
Report of Independent Registered Public Accounting Firm	F-5
Interim Balance Sheet	F-6
Interim Statement of Operations	F-7
Interim Statement of Stockholders’ Equity	F-8
Interim Statement of Cash Flows	F-9
Notes to Interim Financial Statements	F-10
Interim Financial Statements of the Founding Companies of Rex Energy Corporation
Combined Balance Sheets	F-14
Combined Statements of Operations	F-15
Combined Statements of Changes in Owners’ Equity (Deficit) and Minority Interests	F-16
Combined Statements of Cash Flows	F-17
Notes to the Combined Financial Statements	F-18
Annual Financial Statements of the Founding Companies of Rex Energy Corporation
Report of Independent Registered Public Accounting Firm	F-58
Combined Balance Sheets	F-59
Combined Statements of Operations	F-60
Combined Statements of Owners’ Equity (Deficit) and Minority Interests	F-61
Combined Statements of Cash Flows	F-62
Notes to the Combined Financial Statements	F-63
Douglas Oil & Gas Limited Partnership
Report of Independent Registered Public Accounting Firm	F-121
Consolidated Balance Sheets	F-122
Consolidated Statements of Operations	F-123
Consolidated Statements of Partners’ Equity	F-124
Consolidated Statements of Cash Flows	F-125
Notes to Consolidated Financial Statements	F-126
Douglas Westmoreland Limited Partnership
Report of Independent Registered Public Accounting Firm	F-150
Balance Sheets	F-151
Statements of Operations	F-152
Statements of Changes in Partners’ Equity (Deficit)	F-153
Statements of Cash Flows	F-154
Notes to Financial Statements	F-155
Midland Exploration Limited Partnership
Report of Independent Registered Public Accounting Firm	F-171
Balance Sheets	F-172
Statements of Operations	F-173
Statements of Changes in Partners’ Equity	F-174
Statements of Cash Flows	F-175
Notes to Financial Statements	F-176
New Albany-Indiana, LLC
Report of Independent Registered Public Accounting Firm	F-186
Balance Sheets	F-187
Statements of Operations	F-188

F-1

	Page
Statements of Changes in Members’ Equity	F-189
Statements of Cash Flows	F-190
Notes to Financial Statements	F-191
Rex Energy II Limited Partnership
Report of Independent Registered Public Accounting Firm	F-199
Balance Sheets	F-200
Statements of Operations	F-201
Statements of Changes in Partners’ Equity	F-202
Statements of Cash Flows	F-203
Notes to Financial Statements	F-204
Financial Statements Regarding Significant Acquisitions of Rex Energy II Limited Partnership
Oil Property acquired from Hux Oil Corp. and Pioneer Oil Company, Inc.
Independent Auditors’ Report	F-221
Statements of Revenues and Direct Operating Expenses	F-222
Notes to Financial Statements	F-223
Oil Property acquired from National Energy Corporation
Independent Auditors’ Report	F-227
Statements of Revenues and Direct Operating Expenses	F-228
Notes to Financial Statements	F-229
Team Energy, LLC Non-Operated Oil Property acquired
Independent Auditors’ Report	F-233
Statements of Revenues and Direct Operating Expenses	F-234
Notes to Financial Statements	F-235
Rex Energy III LLC
Report of Independent Registered Public Accounting Firm	F-239
Balance Sheet	F-240
Statement of Operations	F-241
Statement of Changes in Members’ Equity	F-242
Statement of Cash Flows	F-243
Notes to Financial Statements	F-244
Financial Statements Regarding Significant Acquisition of Rex Energy III LLC
Oil Property acquired from Team Energy, LLC
Independent Auditors’ Report	F-258
Statements of Revenues and Direct Operating Expenses	F-259
Notes to Financial Statements	F-260
Rex Energy II Alpha Limited Partnership
Report of Independent Registered Public Accounting Firm	F-264
Balance Sheets	F-265
Statements of Operations	F-266
Statements of Changes in Partners’ Equity	F-267
Statements of Cash Flows	F-268
Notes to Financial Statements	F-269
Rex Energy Royalties Limited Partnership
Report of Independent Registered Public Accounting Firm	F-282
Balance Sheets	F-283

F-2

	Page
Statements of Operations	F-284
Statements of Changes in Partners’ Equity	F-285
Statements of Cash Flows	F-286
Notes to Financial Statements	F-287
Rex Energy Operating Corp.
Report of Independent Registered Public Accounting Firm	F-296
Balance Sheets	F-297
Statements of Operations	F-298
Statements of Changes in Stockholders’ Equity (Deficit)	F-299
Statements of Cash Flows	F-300
Notes to Financial Statements	F-301
PennTex Resources, L.P.
Report of Independent Registered Public Accounting Firm	F-312
Balance Sheets	F-313
Statements of Operations	F-314
Statements of Changes in Partners’ Equity (Deficit)	F-315
Statements of Cash Flows	F-316
Notes to Financial Statements	F-317
PennTex Resources Illinois, Inc.
Report of Independent Registered Public Accounting Firm	F-337
Balance Sheets	F-338
Statements of Operations	F-339
Statements of Changes in Stockholder’s Equity (Deficit)	F-340
Statements of Cash Flows	F-341
Notes to Financial Statements	F-342
Financial Statements Regarding Significant Acquisition of PennTex Resources Illinois, Inc.
Oil Property acquired from ERG Illinois, Inc.
Independent Auditors’ Report	F-361
Statement of Revenues and Direct Operating Expenses	F-362
Notes to Financial Statement	F-363
Rex Energy IV LLC
Report of Independent Registered Public Accounting Firm	F-367
Balance Sheet	F-368
Statement of Operations	F-369
Statement of Changes in Members’ Equity (Deficit)	F-370
Statement of Cash Flows	F-371
Notes to Financial Statements	F-372
Financial Statements Regarding Significant Acquisition of Rex Energy IV, LLC
Oil Property acquired from Tsar Energy II, LLC
Independent Auditors’ Report	F-388
Statements of Revenues and Direct Operating Expenses	F-389
Notes to Financial Statements	F-390

F-3

REX ENERGY CORPORATION

INTERIM FINANCIAL STATEMENTS

FOR THE PERIOD FROM

INCEPTION (MARCH 8, 2007) TO MARCH 31, 2007

F-4

Report of Independent Registered Public Accounting Firm

To the Board of Directors of

Rex Energy Corporation

State College, Pennsylvania

We have audited the accompanying interim balance sheet of Rex Energy Corporation as of March 31, 2007 and the related interim statements of operations, changes in partners’ equity and cash flows for the period from inception (March 8, 2007) to March 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the interim financial statements referred to above present fairly, in all material respects, the financial position of Rex Energy Corporation as of March 31, 2007, and the results of their operations and their cash flows for the period from inception (March 8, 2007) to March 31, 2007 in conformity with accounting principles generally accepted in the United States of America.

Pittsburgh, Pennsylvania

July 2, 2007

F-5

REX ENERGY CORPORATION

INTERIM BALANCE SHEET

MARCH 31, 2007

ASSETS
CURRENT ASSETS
CASH	$	10
STOCKHOLDERS’ EQUITY
CAPITAL STOCK AND PAID IN CAPITAL	$	10

See accompanying notes.

F-6

REX ENERGY CORPORATION

INTERIM STATEMENT OF OPERATIONS

FOR THE PERIOD FROM INCEPTION (MARCH 8, 2007) TO MARCH 31, 2007

OPERATING REVENUE	$	0
OPERATING EXPENSES		0
NET INCOME	$	0

See accompanying notes.

F-7

REX ENERGY CORPORATION

INTERIM STATEMENT OF STOCKHOLDERS’ EQUITY

FOR THE PERIOD FROM INCEPTION (MARCH 8, 2007) TO MARCH 31, 2007

	Stockholders’ Equity
BEGINNING BALANCE	$	0
STOCK PURCHASE		10
ENDING BALANCE	$	10

See accompanying notes.

F-8

REX ENERGY CORPORATION

INTERIM STATEMENT OF CASH FLOWS

FOR THE PERIOD FROM INCEPTION (MARCH 8, 2007) TO MARCH 31, 2007

CASH FLOWS PROVIDED BY FINANCING ACTIVITIES
Stock Purchase		10
NET INCREASE IN CASH		10
CASH—BEGINNING		0
CASH—ENDING	$	10

See accompanying notes.

F-9

REX ENERGY CORPORATION

NOTES TO INTERIM FINANCIAL STATEMENTS

FOR THE PERIOD FROM INCEPTION (MARCH 8, 2007) TO MARCH 31, 2007

1. ORGANIZATION OF BUSINESS

Rex Energy Corporation (“Rex Energy” or the “Company”) was incorporated in the State of Delaware on March 8, 2007. The nature of the business and purpose to be conducted or promoted by the Company is to engage in any lawful act or activity for which corporations may be organized under the General Corporation Law of the State of Delaware. The business and affairs of the Company are managed under the direction of the Company’s Board of Directors. The members of the Company’s Board of Directors are Lance T. Shaner, Benjamin W. Hulburt and Thomas F. Shields. At formation, the Company was authorized to issue 2,000 shares of capital stock, of which (i) 1,000 shares were designated as common stock, par value $.001 per share, and (ii) 1,000 shares were designated as preferred stock, par value $.001 per share. The preferred stock may be issued from time to time in one or more series by resolution of the Board of Directors of the Company. The rights, preferences, privileges and restrictions granted to or imposed upon any series of preferred stock and the number of shares of any series of preferred stock may be established by resolution of the Board of Directors of the Company. Except as provided by applicable law or in any certificate of designation of preferred stock, the voting power for the election of directors and for all other purposes is vested exclusively in the holders of the Company’s common stock. On March 30, 2007, the Company issued 6 shares of common stock to Lance T. Shaner and 4 shares of common stock to Benjamin W. Hulburt, each at a price of $1.00 per share. No other shares of common stock are issued or outstanding and no shares of preferred stock are issued or outstanding. The Company did not conduct any operations during the current period. The Company’s year end is December 31, and these are interim statements.

2. SIGNIFICANT ACCOUNTING POLICIES

Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Accordingly, actual amounts could differ from those estimates.

Income Taxes

The Company is taxed as a corporation for federal and state purposes. Since the entity conducted no operations in the current period no provisions were made for income taxes.

3. SUBSEQUENT EVENTS

On April 1, 2007, the Company increased the number of directors serving on its Board of Directors to four and elected John A. Lombardi to serve as a director. On April 23, 2007, the Company amended its certificate of incorporation to increase its authorized shares to 100,100,000 shares of capital stock, of which (i) 100,000,000 shares were designated as common stock, par value $.001 per share, and (ii) 100,000 shares were designated as preferred stock, par value $.001 per share.

F-10

Interim Financial Statements of the

Founding Companies of Rex Energy Corporation

F-11

FOUNDING COMPANIES OF

REX ENERGY

CORPORATION

COMBINED FINANCIAL STATEMENTS

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

F-12

Intentionally Left Blank

F-13

FOUNDING COMPANIES OF REX ENERGY CORPORATION

COMBINED BALANCE SHEETS

ASSETS	March 31, 2007			December 31, 2006
	(Unaudited)
Current Assets
Cash and Cash Equivalents	$	1,591,263		$	599,796
Accounts Receivable		6,926,485			6,884,235
Related Party Receivable		133,221			1,698
Short-Term Derivative Instruments		132,092			1,274,865
Inventory, Prepaid Expenses and Other		2,154,110			1,520,252
Total Current Assets		10,937,171			10,280,846
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		131,086,091			127,370,445
Unevaluated Oil and Gas Properties		9,934,237			14,569,281
Other Property and Equipment		4,122,537			4,181,843
Wells in Progress		1,865,586			2,844,481
Pipelines		1,802,147			1,764,439
Total Property and Equipment		148,810,598			150,730,489
Less: Accumulated Depreciation, Depletion and Amortization		(21,217,104	)		(17,714,633	)
Net Property and Equipment		127,593,494			133,015,856
Other Assets
Other Assets—Net		1,239,996			1,171,795
Long-Term Derivative Instruments		0			142,855
Total Other Assets		1,239,996			1,314,650
Total Assets	$	139,770,661		$	144,611,352
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable and Accrued Expenses	$	8,291,291		$	8,335,580
Short-Term Derivative Instruments		3,205,063			2,977,697
Accrued Distributions		0			102,465
Lines of Credit		38,630,634			37,580,634
Current Portion of Long-Term Debt		11,561,150			2,867,540
Related Party Payable		0			1,820,000
Total Current Liabilities		61,688,138			53,683,916
Long-Term Liabilities
Long-Term Debt		42,311,563			44,961,271
Other Loans and Notes Payable—Long-Term Portion		772,500			481,373
Long-Term Derivative Instruments		3,621,976			1,698,125
Participation Liability—Net		2,141,109			2,141,109
Other Liabilities		393,218			405,080
Asset Retirement Obligation		5,666,279			5,268,482
Total Long-Term Liabilities		54,906,645			54,955,440
Total Liabilities		116,594,783			108,639,356
Commitments and Contingencies (Note 4)
Minority Interests		25,399,110			36,589,360
Owners’ Equity
Common Stock		1,060			1,060
Additional Paid-In Capital		1,460,000			1,460,000
Accumulated Stockholders’ (Deficit)		(420,322	)		(580,578	)
Partners' and Members’ (Deficit)		(3,263,970	)		(1,497,846	)
Total Owners’ Deficit		(2,223,232	)		(617,364	)
Total Liabilities, Minority Interests and Owners’ Deficit	$	139,770,661		$	144,611,352

See accompanying notes to these unaudited financial statements.

F-14

FOUNDING COMPANIES OF REX ENERGY CORPORATION

COMBINED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended March 31,
	2007			2006
OPERATING REVENUE
Oil and Natural Gas Sales	$	12,774,851		$	9,168,791
Other Operating Revenue		100,221			127,143
Realized Gain (Loss) on Hedges		264,838			(1,389,857	)
Unrealized Gain (Loss) on Hedges		(3,436,845	)		119,539
TOTAL OPERATING REVENUE		9,703,065			8,025,616
OPERATING EXPENSES
Operating Expenses		6,105,097			2,443,839
General and Administrative Expense		1,981,995			843,707
Accretion Expense on Asset Retirement Obligation		124,210			97,780
Impairment Charge on Oil and Gas Properties		585,042			0
Depreciation, Depletion, and Amortization		3,949,049			1,967,351
TOTAL OPERATING EXPENSES		12,745,393			5,352,677
INCOME (LOSS) FROM OPERATIONS		(3,042,328	)		2,672,939
OTHER INCOME (EXPENSE)
Interest Income		8,917			35,968
Interest Expense		(2,084,820	)		(766,329	)
Gain (Loss) on Sale of Oil and Gas Properties		176,482			0
Other Income (Expense)		(43,506	)		(113,097	)
TOTAL OTHER INCOME (EXPENSE)		(1,942,927	)		(843,458	)
NET INCOME (LOSS) BEFORE MINORITY INTEREST		(4,985,255	)		1,829,481
MINORITY INTEREST SHARE OF INCOME (LOSS)		(2,727,892	)		921,064
NET INCOME (LOSS)	$	(2,257,363	)	$	908,417

See accompanying notes to these unaudited financial statements.

F-15

FOUNDING COMPANIES OF REX ENERGY CORPORATION

COMBINED STATEMENT OF CHANGES IN OWNERS’ EQUITY (DEFICIT) AND MINORITY INTERESTS

DECEMBER 31, 2006 THROUGH MARCH 31, 2007

(Unaudited)

	Common Stock		Additional Paid In Capital		Stockholders’ Equity			Members’ Equity			Partners’ Equity			Total Owners’ Equity			Minority Interests
BALANCE—December 31, 2006	$	1,060	$	1,460,000	$	(580,578	)	$	5,969,242		$	(7,467,088	)	$	(617,364	)	$	36,589,360
CAPITAL CONTRIBUTIONS												820,000			820,000			300,000
DISTRIBUTIONS												(168,505	)		(168,505	)		(792,000	)
REDEMPTION																		(7,970,357	)
NET INCOME (LOSS)						160,256			(1,452,034	)		(965,585	)		(2,257,363	)		(2,727,892	)
BALANCE—March 31, 2007	$	1,060	$	1,460,000	$	(420,322	)	$	4,517,208		$	(7,781,178	)	$	(2,223,232	)	$	25,399,110

See accompanying notes to these unaudited financial statements.

F-16

FOUNDING COMPANIES OF REX ENERGY CORPORATION

COMBINED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Three Months Ended March 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(2,257,363	)	$	908,417
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Minority Interest Share of Income (Loss)		(2,727,892	)		921,064
Depreciation, Depletion, and Amortization		3,949,049			1,967,351
Unrealized (Gain) Loss on Hedges		3,436,845			(119,539	)
Impairment of Oil and Gas Properties		585,042			0
Accretion Expense on Asset Retirement Obligation		124,210			97,780
Plugging Costs Incurred		(30,366	)		0
(Gain) Loss on Sale of Oil and Gas Properties		(176,482	)		0
Cash Flows from Operating Activities Due to
(Increase) in Accounts Receivable		(173,773	)		(1,636,496	)
(Increase) Decrease in Inventory, Prepaid Expenses and Other Assets		(64,178	)		242,088
Increase (Decrease) in Accounts Payable and Accrued Expenses		(44,289	)		(856,250	)
Net Changes in Other Assets and Liabilities		(350,067	)		(41,011	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		2,270,736			1,483,404
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Oil and Gas Properties, Prospects and Other Assets		223,500			0
Acquisitions of Oil & Gas Properties		(1,080,000	)		(18,305,255	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(4,959,470	)		(1,283,938	)
NET CASH USED IN INVESTING ACTIVITIES		(5,815,970	)		(19,589,193	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Proceeds from (Repayments of) Long-Term Debts and Lines of Credit		7,093,902			16,542,831
Net Proceeds from (Repayments of) Loans and Other Notes Payable		291,127			129,800
Net Proceeds from (Repayments to) Related Parties		(1,000,000	)		(8,136,423	)
Financing Costs Paid		(515,678	)		(583,252	)
Deferred Offering Costs Paid		(569,680	)		0
Capital Contributions		300,000			15,028,010
Cash Distributions		(1,062,970	)		(6,232,779	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		4,536,701			16,748,187
NET (DECREASE) INCREASE IN CASH		991,467			(1,357,602	)
CASH—BEGINNING		599,796			2,687,550
CASH—ENDING	$	1,591,263		$	1,329,948
SUPPLEMENTAL DISCLOSURES
Interest Paid	$	2,084,820		$	766,329
Non-Cash Activities
Redemption—Baseline Property Distribution	$	7,970,357		$	0
Conversion of Lance T. Shaner Loan Payable to Capital	$	820,000		$	0
Repayment of Lance T. Shaner via Transfer of New Albany Interests	$	0		$	1,715,000
Accrued Distribution	$	0		$	28,900
Conversion of Deposit of leasehold acreage to leasehold acquisitions	$	0		$	3,500,000

See accompanying notes to these unaudited financial statements.

F-17

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Reporting

The interim combined financial statements of Rex Energy Corporation (the “Company”) are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part, but not limited to, the volatility in prices for crude oil and natural gas, future commodity prices for financial derivative instruments, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market consumption, interruption in production, the Company’s ability to obtain additional capital, and the success of oil and natural gas recovery techniques. You should read these combined interim financial statements in conjunction with the audited combined financial statements and notes thereto included in the Company’s Registration Statement on Form S-1 dated April 27, 2007.

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of the Founding Companies of Rex Energy Corporation. All of the Founding Companies are under the common control of Lance T. Shaner through his direct and indirect ownership interests and other contractual arrangements, as well as under the common management of Rex Energy Operating Corp. All material intercompany balances and transactions have been eliminated. Since each of the Founding Companies was taxed as a partnership or Subchapter S corporation for each of the periods indicated for federal and state income tax purposes, the combined financial statements make no provision for income taxes.

The following table defines the Founding Companies of Rex Energy Corporation and the associated ownership interest as of March 31, 2007:

		Lance T. Shaner Interest		Minority Interest
Douglas Oil & Gas Limited Partnership	“Douglas Oil & Gas”	13.70	%	86.30	%
Douglas Westmoreland Limited Partnership	“Douglas Westmoreland”	13.70	%	86.30	%
Rex Energy Royalties Limited Partnership	“Rex Royalties”	5.16	%	94.84	%
Midland Exploration Limited Partnership	“Midland”	2.52	%	97.48	%
New Albany-Indiana, LLC	“New Albany”	40.04	%	59.96	%
PennTex Resources Illinois, Inc.	“PennTex Illinois”	100.00	%	0.00	%
PennTex Resources, L.P.	“PennTex Resources”	100.00	%	0.00	%
Rex Energy Limited Partnership	“Rex I”	22.28	%	77.72	%
Rex Energy II Limited Partnership	“Rex II”	11.10	%	88.90	%
Rex Energy II Alpha Limited Partnership	“Rex II Alpha”	0.00	%	100.00	%
Rex Energy III LLC	“Rex III”	46.50	%	53.50	%
Rex Energy IV, LLC	“Rex IV”	50.00	%	50.00	%
Rex Energy Operating Corp.	“Rex Operating”	60.00	%	40.00	%

Income Taxes

The Founding Companies are treated as partnerships and Subchapter S corporations for federal and state income tax purposes. Accordingly, income taxes are not reflected in the combined financial statements because the resulting profit or loss is included in the income tax returns of the individual stockholders, members or partners.

F-18

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

Revenue Recognition

Natural gas revenue is recognized when the natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of gas purchased (although there are provisions for challenging these measurements if the Company believes the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for natural gas purchases within 30-60 days of the end of each production month. The Company periodically reviews the difference between the dates of production and the dates it collects payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for the Company’s natural gas production is at its applicable field gathering system; therefore, the Company does not incur transportation costs related to our sales of natural gas production. The Company does not currently participate in any gas-balancing arrangements.

Oil revenue is recognized when the oil is delivered to or collected by the purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves our stock tanks and enters the purchaser’s trucks. It is the measurement of the purchaser that determines the amount of oil purchased (although there are provisions for challenging these measurements if the Company believes the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil purchases within 30 days of the end of each production month. The Company periodically reviews the difference between the dates of production and the dates it collects payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for the Company’s oil production is at its applicable field gathering system; therefore, the Company does not incur transportation costs related to our sales of oil production.

The Company uses the allowance method to account for uncollectible accounts receivable. At both March 31, 2007 and December 31, 2006, management determined the allowance for uncollectible receivables to be $172,663.

Distributions to Partners

During the three months ended March 31, 2007 certain of the Founding Companies made distributions to the respective partners of such Founding Companies. Rex Royalties made distributions to its partners of $107,631 during the period. Douglas Oil & Gas made distributions to its partners of $248,903 during the period, $218,902 of which was distributed to Rex I which was subsequently distributed to the partners of Rex I. Midland Exploration made distributions to its partners of $102,465 during the period, all of which were accrued at December 31, 2006, and of which $15,225 was distributed to Douglas Oil & Gas. Rex II made distributions to its partners of $569,196 during the period. Rex II Alpha made distributions to its partners during the period of $50,000.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the combined financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

F-19

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues, asset retirement obligations, impairment (when applicable) of undeveloped properties, the collectibility of outstanding accounts receivable, fair values of financial derivative instruments, contingencies, and the results of current and future litigation. Oil and natural gas estimates, which are the basis for unit-of-production depletion, have numerous inherent uncertainties. The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing, and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

The significant estimates are based on current assumptions that may be materially effected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, and the Company’s ability to generate future income. Future changes in these assumptions may materially affect these significant estimates in the near term.

Derivative Instruments

The Company uses put and call options (collars) and fixed rate swap contracts to manage price risks in connection with the sale of oil and natural gas. The Company accounts for these contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The results of these activities are reflected in the revenue section of the Combined Statements of Operations.

The Company has established the fair value of all derivative instruments using estimates determined by its counterparties. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. The values the Company reports in its combined financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

SFAS No. 133 establishes accounting and reporting standards requiring derivative instruments (including certain derivative instruments embedded in other contracts or agreements) be recorded at fair value and included in the Combined Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in earnings.

For derivative instruments designated as fair value hedges (in accordance with SFAS No. 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Hedge effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. However, the Company’s evaluations are not documented, and as a result, the Company is recording changes on the derivative valuations through earnings.

Oil and Natural Gas Property, Depreciation and Depletion

The Company accounts for its natural gas and oil exploration and production activities under the successful efforts method of accounting.

F-20

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

Proved developed natural gas and oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of natural gas and oil are capitalized.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years.

The Company accounts for impairment under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future natural gas and oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

Based on information that became available subsequent to March 31, 2007, management determined that a well in progress, by Rex II, one of the Founding Companies, at March 31, 2007 was impaired. Costs incurred as of March 31, 2007, related to this well in the amount of $585,042, were expensed in the current quarter. Management estimates that approximately $1.10 million of additional costs incurred during the three months ended June 30, 2007 to complete the drilling of this well will be expensed during the second quarter ending June 30, 2007. Management determined that no adjustments to the carrying value of long-lived assets were necessary for the three months and year ended March 31, 2006 and December 31, 2006.

Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

F-21

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

Asset Retirement Obligations

The Company accounts for future abandonment costs using SFAS No. 143, “Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS No. 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of the Company’s natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. The asset retirement obligation is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0%. See Note 12 for detail concerning the individual Founding Companies.

	March 31, 2007			December 31, 2006
Beginning Balance	$	5,268,482		$	2,358,158
Initial Asset Retirement Obligation Capitalized		280,197			2,506,248
Plugging Costs Incurred and Adjustments		(6,610	)		(71,425	)
Asset Retirement Obligation Accretion Expense		124,210			475,501
Total Asset Retirement Obligation	$	5,666,279		$	5,268,482

New Accounting Pronouncements

On February 15, 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of SFAS No. 115. This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. This option is available to all entities, including not-for-profit organizations. Most of the provisions in Statement 159 are elective; however, the amendment to SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, applies to all entities with available-for-sale and trading securities. The fair value option established by Statement 159 permits all entities to choose to measure eligible items at fair value at specified election dates. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings (or another performance indicator if the business entity does not report earnings) at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective as of January 1, 2008. Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity makes that choice in the first 120 days of that fiscal year and also elects to apply the provisions of SFAS No. 157, Fair Value Measurements. The Company is currently evaluating the effect that the implementation of SFAS 159 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. The Company adopted the provisions of FIN 48 for its year ending December 31, 2007. As the Founding

F-22

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

Companies are treated as partnerships and Subchapter S corporations for federal and state income tax purposes, the adoption of FIN 48 did not have an impact on results of operations and financial condition. The Company is currently evaluating the effect of FIN 48 upon the completion of the merger transactions by which the Company will acquire the operations of the Founding Companies, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

2. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSALS

Rex II

On February 26, 2007, Rex II acquired a 90.0% working interest in 6 oil and gas leases covering properties located in Hardin County, Texas for $1,080,000. The acquisition included interests in 3 producing oil wells and related infrastructure and equipment. The interests were purchased from the Creditor’s Trust for Central Utilities Production Corp., a creditor’s trust established in connection with a bankruptcy case styled In re Central Utilities Production Corp., Case No. 03-44067, filed in the United States Bankruptcy Court, Eastern District of Texas, Sherman Division. The effective date of the acquisition was February 1, 2007.

On February 21, 2007, Rex II and Rex II Alpha sold their interest in a well for $220,000 and recorded a total gain on sale in the amount of $172,982.

3. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value of the Company’s long-term debt instruments approximates the fair value as the debt facilities carry a market rate of interest.

The Company estimates the fair value of the participation liability associated with a prior Norguard Insurance Company’s term loan to be $2,141,109 to Douglas Westmoreland, one of the Founding Companies, as of March 31, 2007 and December 31, 2006, respectively.

The fair value of the net liability associated with the Company’s derivative instruments was $6,694,947 and $3,258,102 at March 31, 2007 and December 31, 2006, respectively. The fair value is based on valuation methodologies of the Company’s counterparties. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

F-23

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

4. COMMITMENTS AND CONTINGENCIES

Legal Reserves

At March 31, 2007 and December 31, 2006, the Company’s Combined Balance Sheet included reserves for the legal proceedings detailed in Note 10: Litigation of $838,848 and $891,000, respectively. The accrual of reserves for legal matters is included in Accrued Expenses on the Combined Balance Sheet. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional loss, the amount of which is not currently estimable, in excess of the amounts currently accrued with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in actual liability exceeding the estimated ranges of loss and the amounts accrued. Based on currently available information, the Company believes that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed current accruals by an amount that would have a material adverse effect on the combined financial position or results of operations of the Company, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

Environmental

Due to the nature of the natural gas and oil business, the Company is exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. It conducts periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort.

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. Except as described in Note 10: Litigation, management knows of no significant probable or possible environmental contingent liabilities.

Letters of Credit

Douglas Westmoreland has posted a $50,000 letter of credit with the Commonwealth of Pennsylvania to secure its drilling and related operations on Keystone State Park in Westmoreland County, Pennsylvania.

Other

In addition to the Asset Retirement Obligation discussed in Note 1, Douglas Oil & Gas has withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. Such amounts totaling $325,036 are included in Other Liabilities at March 31, 2007 and December 31, 2006.

5. LINES OF CREDIT

Rex IV

Rex IV entered into a Credit Agreement dated as of October 2, 2006 with KeyBank National Association (“KeyBank”), as Administrative Agent on behalf of signatory lenders which are parties to the agreement from

F-24

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

time to time. The credit facility established under the Credit Agreement provides for loans and letters of credit of up to a maximum of $40,000,000. On October 1, 2006, Rex IV borrowed $36,580,634 under the new credit facility to pay the purchase price for the acquisition of certain oil properties from Tsar Energy II, LLC.

On March 30, 2007, Rex IV and KeyBank executed a First Amendment to the Credit Agreement which extended the maturity date of borrowings under the credit agreement to the earlier of (i) the date of closing of the Company’s initial public offering or (ii) December 31, 2007. In addition, the First Amendment provided for a change in the interest rate per annum for Eurodollar borrowings to the LIBO rate plus 400 basis points. The First Amendment to the Credit Agreement also provided for revisions to certain negative covenants contained in the credit agreement. The ratio of total debt to EBITDAX was changed from 5.75:1.00 to 7.00:1.00 for the fiscal quarter ending June 30, 2007, 6.75:1.00 for the fiscal quarter ending September 30, 2007 and 6.50:1.00 for the fiscal quarter ending December 31, 2007. The First Amendment also provided that for the purposes of calculating both ratios, EBITDAX excludes non-reoccurring legal expenses of Rex IV.

At March 31, 2007, the outstanding balance on the line of credit was $38,630,634, of which $37,750,000 incurred interest at 8.32% and $880,634 incurred interest at 10.25%.

6. LONG-TERM DEBT

Long-term debt consists of the following at March 31, 2007 and December 31, 2006:

	March 31, 2007			December 31, 2006
Douglas M&T Loan	$	8,991,586		$	8,941,586
PennTex M&T Credit Facility		17,344,536			14,944,536
Rex II Credit Facility		7,442,027			3,550,149
Rex III Credit Agreement		20,000,000			20,000,000
Other Loans and Notes Payable		867,064			873,913
Total Debts		54,645,213			48,310,184
Less Current Portion		(11,561,150	)		(2,867,540	)
Total Long-Term Debts	$	43,084,063		$	45,442,644

Douglas Oil & Gas and Douglas Westmoreland Term Loan—M&T Bank

On February 13, 2006, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, entered into a revolving line of credit of up to $10,000,000 with Manufacturers and Traders Trust Company, as agent (the “Douglas M&T Loan”). The Borrowing Base for the Douglas M&T Loan as of March 31, 2007 and December 31, 2006 was $10,000,000 and 9,500,000, respectively. Interest on the loan accrues and is payable at a rate per annum equal to the base rate from time to time in effect, plus one percent (1.0%). The base rate is equal to the rate of interest per annum then most recently established by M&T Bank as its “prime rate”, which rate may not be the lowest rate of interest charged by M&T Bank to its borrowers. There are no principal payments due monthly. The loan matures on February 13, 2009. The borrowers are jointly and severally liable with respect to borrowings under the Douglas M&T Loan.

The outstanding balance on the Douglas M&T Term Loan as of March 31, 2007 and December 31, 2006 was $8,991,586 and $8,941,586, respectively. The interest rate at March 31, 2007 was 9.25%.

F-25

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

As of March 31, 2007, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, were not in compliance with the negative covenant in their credit agreement which states that the co-borrowers will not allow their Minimum Fixed Coverage Charge, as defined in the credit agreement, to be at least 1.25. The Company is in discussions with the lender to obtain a waiver, and has reclassified this long-term debt as current.

As of March 31, 2007 and December 31, 2006, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, were not in compliance with the negative covenant in the credit agreement which states that the co-borrowers will not permit their tangible net worth, on a combined basis, as of the end of any fiscal year to be less than such amount that is 15.0% less than the tangible net worth of the co-borrowers as indicated on their audited year end financial statements as of December 31, 2005; provided, however, that commencing on December 31, 2006, and at the end of each fiscal year thereafter, this amount will increase by $500,000. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarters of 2007.

PennTex Illinois and PennTex Resources Credit Facility—M&T Bank

On January 19, 2006, PennTex Illinois and PennTex Resources, as co-borrowers, entered into a revolving line of credit of up to $22,500,000 with Manufacturers and Traders Trust Company, as agent (the “PennTex M&T Credit Facility”). The Borrowing Base for the PennTex M&T Credit Facility was $18,500,000 as of March 31, 2007 and December 31, 2006. Interest on the credit facility accrues and is payable at a rate per annum equal to the base rate from time to time in effect, plus one percent (1.0%). The credit facility matures on January 16, 2009. The outstanding balance at March 31, 2007 and December 2006 was $17,344,536 and $14,944,536, respectively. The interest rate on the line of credit as of March 31, 2007 was 9.25%.

As of March 31, 2007, PennTex Illinois and PennTex Resources were not in compliance with the negative covenant in their credit agreement requiring that their ratio of current assets to current liabilities, as defined in the credit agreement, be at least 1.1:1. The companies have received a waiver of this covenant for the first and second quarters of 2007.

Rex II Credit Facility—Sovereign Bank

On March 24, 2006, Rex II entered into a revolving line of credit for up to $3,700,000 with Sovereign Bank. Interest on the loan accrues and is equal to the rate of interest per annum from time to time established by Sovereign Bank as its prime rate of interest. On February 13, 2007, Rex II entered into an Amended and Restated Credit Agreement dated as of February 13, 2007 with Sovereign Bank, as Administrative Agent and Lead Arranger on behalf of signatory lenders which are parties to the agreement from time to time. At the closing of this loan transaction, the outstanding balance under Rex II’s revolving line of credit with Sovereign Bank of $3,592,027 was refinanced and became an outstanding obligation under the new credit facility. The new credit facility provides for loans and letters of credit of up to a maximum of $10,000,000. Borrowings under the new credit facility mature on March 24, 2008.

As of March 31, 2007 and December 31, 2006, outstanding borrowings under the credit facility were $7,442,027 and $3,550,149, respectively. The interest rate at March 31, 2007 was equal to 8.75%.

Rex III Credit Agreement—M&T Bank

On June 28, 2006, Rex III entered into a Credit Agreement with Manufacturers and Traders Trust Company (“M&T Bank”), as Letter of Credit Issuer, Lead Arranger and Agent on behalf of signatory lenders which are

F-26

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

parties to the agreement from time to time. The credit facility established under the Credit Agreement provides for loans and letters of credit of up to a maximum of $20,000,000. The Credit Agreement provides for a revolving credit loan up to a maximum of $15,000,000 and for term loans in the amount of up to $5,000,000. Interest on each advance under the revolving credit loan and the term loans accrues and is payable at a rate per annum selected by Rex III at either a LIBOR based rate or the applicable floating rate. The revolving credit loan terminates on June 27, 2009.

The term loan matures on December 27, 2008. The principal balance of the term loans is payable as follows:

Payment Date	Principal Amount Due
June 27, 2007	$625,000.00
December 27, 2007	$1,250,000.00
June 27, 2008	$1,250,000.00
December 27, 2008	The lesser of $1,875,000.00 or the then outstanding principal balance of the term loans.

At both March 31, 2007 and December 31, 2006, outstanding borrowings under the credit facility were $20,000,000, of which $15,000,000 was under the revolving credit loan and $5,000,000 was under the term loan. As of March 31, 2007, the interest rate associated with the revolving credit loan and term loan was 8.32% and 10.82%, respectively.

As of March 31, 2007, Rex III was not in compliance with the negative covenant contained in its credit agreement requiring that its ratio of total reserve value to total funded debt, as defined in the credit agreement, be at least 2.5:1. Rex III obtained a written waiver from its lenders regarding its non-compliance with this negative covenant for the first and second quarter of 2007.

Other Loans and Notes Payable

Other loans and notes payable relate to financings obtained in the normal course of business to acquire vehicles, office equipment and leasehold improvements.

7. FINANCIAL DERIVATIVE INSTRUMENTS

The Company’s results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, the Company entered into oil and natural gas derivative instruments. As of March 31, 2007 and December 31, 2006, the Company’s oil and natural gas derivative instruments consisted of fixed rate swap contracts and collars. These instruments allow the Company to predict with greater certainty the effective oil and natural gas price to be received for the Company’s hedged production.

Collars contain a fixed floor price (put) and ceiling price (call). The put options are purchased from the counterparty by the Company’s payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays the Company an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty by the Company’s receipt of a cash premium. If the market price is greater than the call strike price for a calculation period, then the Company pays the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.

F-27

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

The Company sells oil and natural gas in the normal course of business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in oil and natural gas sales. The Company enters into derivative instruments such as swap contracts to hedge a portion of its forecasted oil and natural gas sales.

The Company received (incurred) net payments of $264,838 and ($1,389,857) under these derivative instruments during the three months ended March 31, 2007 and 2006, respectively. Unrealized gains (losses) associated with these derivative instruments are included in operating revenue and amounted to ($3,436,845) and $119,539 for the three months ended March 31, 2007 and 2006, respectively.

F-28

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

The Company’s open asset/(liability) financial derivative instrument positions at March 31, 2007 consisted of:

Derivative Instrument	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Floor Price		Ceiling Price		Fixed Price		Fair Market Value
Swap Contracts		189,000	Apr. 07 –Dec. 07					$	65.46	$	(534,924	)
Swap Contracts		30,000	Apr. 07 –Dec. 07					$	64.75		(119,694	)
Collars		8,000	Apr. 07 –Apr. 07	$	34.00	$	38.35				(222,745	)
Swap Contracts		6,000	Apr. 07 – Sep. 07					$	59.75		(44,057	)
Collars	450,000		Apr. 07 – Dec. 07	$	7.91	$	13.23				140,930
Collars		72,000	Apr. 07 – Dec. 07	$	40.00	$	42.55				(1,847,880	)
Swap Contracts		36,000	Apr. 07 – Dec. 07					$	68.25		(18,475	)
Collars		36,000	Apr. 07 – Dec. 07	$	55.00	$	61.25				(300,779	)
Collars		18,000	Apr. 07 – Dec. 07	$	70.00	$	82.60				73,576
Collars	180,000		Apr. 07 – Dec. 07	$	6.67	$	12.95				(35,839	)
Collars		56,000	May 07 –Dec. 07	$	50.00	$	70.34				(145,295	)
Collars		96,000	Apr. 07 –Mar. 08	$	65.00	$	76.00				66,641
Collars		21,000	Jan. 08 – Mar. 08	$	62.00	$	70.00				(65,407	)
Collars	150,000		Jan. 08 – Mar. 08	$	7.00	$	9.35				(88,576	)
Collars		36,000	Jan. 08 – Mar. 08	$	60.00	$	89.25				54,762
Collars		10,000	Feb. 08 –Mar. 08	$	65.00	$	80.20				14,791
Total Current Portion	780,000	614,000								$	(3,072,971	)
Swap Contracts		204,000	Jan. 08 – Dec. 08					$	65.58		(720,966	)
Collars		32,000	Apr. 08 – Jul. 08	$	65.00	$	76.00				10,490
Collars		28,000	Apr. 08 – Jul. 08	$	62.00	$	70.00				(87,210	)
Collars	450,000		Apr. 08 – Dec. 08	$	7.00	$	9.35				(265,728	)
Collars		108,000	Apr. 08 – Dec. 08	$	60.00	$	89.25				185,183
Collars		45,000	Apr. 08 – Dec. 08	$	65.00	$	80.20				70,082
Collars		40,000	Aug. 08 –Dec. 08	$	62.00	$	69.10				(135,763	)
Collars		60,000	Aug. 08 – Jul. 09	$	65.00	$	76.05				43,109
Collars		175,000	Jan. 09 – Jul. 09	$	62.00	$	67.80				(606,544	)
Collars	600,000		Jan. 09 – Dec. 09	$	7.00	$	9.00				(269,907	)
Collars		140,000	Aug. 09 –Dec. 09	$	62.00	$	66.10				(491,061	)
Swap Contracts		192,000	Jan. 09 – Dec. 09					$	64.00		(564,686	)
Swap Contracts		180,000	Jan. 10 – Dec. 10					$	62.20		(788,975	)
Total Long-Term Portion	1,050,000	1,204,000								$	(3,621,976	)
Total Derivative Instruments	1,830,000	1,818,000								$	(6,694,947	)

F-29

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

Penntex Resources, L.P.

The Company’s open asset/(liability) financial derivative instrument positions at March 31, 2007 consisted of:

Derivative Instrument	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Floor Price		Ceiling Price		Fixed Price		Fair Market Value
Swap Contracts		30,000	Apr. 07 – Dec. 07					$	64.75	$	(119,694	)
Collars		8,000	Apr. 07 – Apr. 07	$	34.00	$	38.35				(222,745	)
Swap Contracts		18,000	Apr. 07 – Dec. 07					$	68.25		(9,238	)
Collars		56,000	May 07 – Dec. 07	$	50.00	$	70.34				(145,295	)
Collars		12,000	Jan. 08 – Mar. 08	$	62.00	$	70.00				(37,376	)
Collars		10,000	Feb. 08 – Mar. 08	$	65.00	$	80.20				14,791
Total Current Portion	—	134,000								$	(519,557	)
Collars		16,000	Apr. 08 – Jul. 08	$	62.00	$	70.00				(49,834	)
Collars		20,000	Aug. 08 – Dec. 08	$	62.00	$	69.10				(67,881	)
Collars		59,500	Jan. 09 – Jul. 09	$	62.00	$	67.80				(206,225	)
Collars		40,000	Aug. 09 – Dec. 09	$	62.00	$	66.10				(140,304	)
Total Long-Term Portion	—	135,500								$	(464,244	)
Total Derivative Instruments	—	269,500								$	(983,801	)

Penntex Resources Illinois, Inc.

The Company’s open asset/(liability) financial derivative instrument positions at March 31, 2007 consisted of:

Derivative Instrument	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Floor Price		Ceiling Price		Fixed Price	Fair Market Value
Collars		72,000	Apr. 07 – Dec. 07	$	40.00	$	42.55		$	(1,847,880	)
Collars		24,000	Jan. 08 – Mar. 08	$	60.00	$	89.25			36,508
Total Current Portion	—	96,000							$	(1,811,372	)
Collars		72,000	Apr. 08 – Dec. 08	$	60.00	$	89.25			123,455
Collars		45,000	Apr. 08 – Dec. 08	$	65.00	$	80.20			70,082
Collars		59,500	Jan. 09 – Jul. 09	$	62.00	$	67.80			(206,225	)
Collars		40,000	Aug. 09 – Dec. 09	$	62.00	$	66.10			(140,303	)
Total Long-Term Portion	—	216,500							$	(152,991	)
Total Derivative Instruments	—	312,500							$	(1,964,363	)

F-30

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

Rex Energy Royalties, L.P.

The Company’s open asset/(liability) financial derivative instrument positions at March 31, 2007 consisted of:

Derivative Instrument	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Floor Price		Ceiling Price		Fixed Price	Fair Market Value
Collars	45,000		Apr. 07 –Dec. 07	$	6.67	$	12.95		$	(25,149	)
Total Current Portion	45,000	—							$	(25,149	)
Total Long-Term Portion	—	—							$	—
Total Derivative Instruments	45,000	—							$	(25,149	)

Douglas Oil and Gas, L.P.

The Company’s open asset/(liability) financial derivative instrument positions at March 31, 2007 consisted of:

Derivative Instrument	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Floor Price		Ceiling Price		Fixed Price	Fair Market Value
Collars	225,000		Apr. 07 – Dec. 07	$	7.91	$	13.23		$	70,465
Collars	60,000		Jan. 08 – Mar. 08	$	7.00	$	9.35			(35,430	)
Total Current Portion	285,000	—							$	35,035
Collars	180,000		Apr. 08 – Dec. 08	$	7.00	$	9.35			(106,291	)
Collars	240,000		Jan. 09 – Dec. 09	$	7.00	$	9.00			(107,963	)
Total Long-Term Portion	420,000	—							$	(214,254	)
Total Derivative Instruments	705,000	—							$	(179,219	)

F-31

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

Douglas Westmoreland, L.P.

The Company’s open asset/(liability) financial derivative instrument positions at March 31, 2007 consisted of:

Derivative Instrument	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Floor Price		Ceiling Price		Fixed Price	Fair Market Value
Collars	225,000		Apr. 07 – Dec. 07	$	7.91	$	13.23		$	70,465
Collars	60,000		Jan. 08 – Mar. 08	$	7.00	$	9.35			(35,430	)
Total Current Portion	285,000	—							$	35,035
Collars	180,000		Apr. 08 – Dec. 08	$	7.00	$	9.35			(106,291	)
Collars	240,000		Jan. 09 – Dec. 09	$	7.00	$	9.00			(107,963	)
Total Long-Term Portion	420,000	—							$	(214,254	)
Total Derivative Instruments	705,000	—							$	(179,219	)

Rex Energy II, L.P.

The Company’s open asset/(liability) financial derivative instrument positions at March 31, 2007 consisted of:

Derivative Instrument	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Floor Price		Ceiling Price		Fixed Price		Fair Market Value
Swap Contracts		6,000	Apr. 07 – Sep. 07					$	59.75	$	(44,057	)
Swap Contracts		9,000	Apr. 07 – Dec. 07					$	68.25		(4,618	)
Collars		36,000	Apr. 07 – Dec. 07	$	55.00	$	61.25				(300,779	)
Collars		18,000	Apr. 07 – Dec. 07	$	70.00	$	82.60				73,576
Collars	135,000		Apr. 07 – Dec. 07	$	6.67	$	12.95				(10,690	)
Collars		8,636	Jan. 08 – Mar. 08	$	62.00	$	70.00				(26,899	)
Collars	28,740		Jan. 08 – Mar. 08	$	7.00	$	9.35				(16,972	)
Collars		12,000	Jan. 08 – Mar. 08	$	60.00	$	89.25				18,254
Total Current Portion	163,740	89,636								$	(312,185	)
Collars		11,515	Apr. 08 – Jul. 08	$	62.00	$	70.00				(35,866	)
Collars	86,220		Apr. 08 – Dec. 08	$	7.00	$	9.35				(50,914	)
Collars		36,000	Apr. 08 – Dec. 08	$	60.00	$	89.25				61,728
Collars		9,596	Aug. 08 – Dec. 08	$	62.00	$	69.10				(32,570	)
Collars		47,020	Jan. 09 – Jul. 09	$	62.00	$	67.80				(162,971	)
Collars	114,960		Jan. 09 – Dec. 09	$	7.00	$	9.00				(51,714	)
Collars		28,788	Aug. 09 – Dec. 09	$	62.00	$	66.10				(100,976	)
Total Long-Term Portion	201,180	132,919								$	(373,283	)
Total Derivative Instruments	364,920	222,555								$	(685,468	)

F-32

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

Rex Energy II Alpha, L.P.

The Company’s open asset/(liability) financial derivative instrument positions at March 31, 2007 consisted of:

Derivative Instrument	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Floor Price		Ceiling Price		Fixed Price	Fair Market Value
Collars		364	Jan. 08 – Mar. 08	$	62.00	$	70.00		$	(1,132	)
Collars	1,260		Jan. 08 – Mar. 08	$	7.00	$	9.35			(744	)
Total Current Portion	1,260	364							$	(1,876	)
Collars		485	Apr. 08 – Jul. 08	$	62.00	$	70.00			(1,510	)
Collars	3,780		Apr. 08 – Dec. 08	$	7.00	$	9.35			(2,232	)
Collars		404	Aug. 08 – Dec. 08	$	62.00	$	69.10			(1,371	)
Collars		1,980	Jan. 09 – Jul. 09	$	62.00	$	67.80			(6,861	)
Collars	5,040		Jan. 09 – Dec. 09	$	7.00	$	9.00			(2,267	)
Collars		1,212	Aug. 09 – Dec. 09	$	62.00	$	66.10			(4,251	)
Total Long-Term Portion	8,820	4,081							$	(18,492	)
Total Derivative Instruments	10,080	4,445							$	(20,368	)

Rex Energy III, LLC

The Company’s open asset/(liability) financial derivative instrument positions at March 31, 2007 consisted of:

Derivative Instrument	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Floor Price		Ceiling Price		Fixed Price		Fair Market Value
Swap Contracts		9,000	Apr. 07 – Dec. 07					$	68.25	$	(4,619	)
Collars		96,000	Apr. 07 – Mar. 08	$	65.00	$	76.00				66,641
Total Current Portion	—	105,000								$	62,022
Collars		32,000	Apr. 08 – Jul. 08	$	65.00	$	76.00				10,490
Collars		10,000	Aug. 08 – Dec. 08	$	62.00	$	69.10				(33,941	)
Collars		60,000	Aug. 08 – Jul. 09	$	65.00	$	76.05				43,109
Collars		7,000	Jan. 09 – Jul. 09	$	62.00	$	67.80				(24,262	)
Collars		30,000	Aug. 09 – Dec. 09	$	62.00	$	66.10				(105,227	)
Total Long-Term Portion	—	139,000								$	(109,831	)
Total Derivative Instruments	—	244,000								$	(47,809	)

F-33

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

Rex Energy IV, LLC

The Company’s open asset/(liability) financial derivative instrument positions at March 31, 2007 consisted of:

Derivative Instrument	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Floor Price	Ceiling Price	Fixed Price		Fair Market Value
Swap Contracts		189,000	Apr. 07 – Dec. 07			$	65.46	$	(534,924	)
Total Current Portion	—	189,000						$	(534,924	)
Swap Contracts		204,000	Jan. 08 – Dec. 08			$	65.58		(720,966	)
Swap Contracts		192,000	Jan. 09 – Dec. 09			$	64.00		(564,686	)
Swap Contracts		180,000	Jan. 10 – Dec. 10			$	62.20		(788,975	)
Total Long-Term Portion	—	576,000						$	(2,074,627	)
Total Derivative Instruments	—	765,000						$	(2,609,551	)

8. RELATED PARTY TRANSACTIONS

At December 31, 2006, there was a working capital loan payable to Lance T. Shaner in the amount of $1,820,000 with no term or due date. During the three months ended March 31, 2007, the amount due was satisfied by converting $820,000 as a capital contribution to PennTex Resources and repaying $1,000,000.

Included in Other Assets at March 31, 2007 and December 31, 2006 is a $20,000 investment in an unconsolidated related party, which represents Rex I’s 100.0% membership interest in Rex Energy, LLC.

Included in accounts receivable is $66,852 due from Shaner & Hulburt Capital Partners Limited Partnership, a related party.

Included in accounts receivable are loans to three employees. These loans are in the form of prepaid compensation. The loans are forgiven if the employees continue to be employed by the Company over periods ranging from 3 to 5 years. The loans will be expensed over the 3 to 5 year service terms. If the employee’s employment with the Company is terminated for any reason, the outstanding balance of the loan is immediately due and payable. The balance of these loans was $64,667 at March 31, 2007 and December 31, 2006.

Accounts receivable at March 31, 2007 and December 31, 2006 also include $1,705 and $32,817 for amounts advanced to fund employees’ health savings accounts, which will be repaid through payroll withholdings throughout the year.

On September 1, 2006, Shaner Brothers, LLC, a related party, loaned $264,656 to Rex Operating to fund its expenses relating to the construction of the interior portions of its headquarters office building. The promissory note provides for the payment of interest on the unpaid principal sum at a rate of 7.0% per annum. The loan must be repaid in 60 consecutive equal monthly installments of principal and interest in the amount of $5,240. The promissory note matures on September 1, 2011, but may be prepaid in whole or in part at anytime, without premium or penalty. At March 31, 2007 and December 31, 2006, the outstanding principal amount of the loan was $242,150 and $253,501, respectively. The Company believes that the terms of this loan are comparable to terms that could be obtained at an arms’ length basis from unrelated lenders.

F-34

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

Rex Operating obtains certain administrative services (such as human resources, information technology, payroll, and tax services) from Shaner Solutions Limited Partnership, a Delaware limited partnership controlled by Lance T. Shaner (“Shaner Solutions”), pursuant to an oral month-to-month agreement providing for a monthly fee of $15,000, plus reimbursement for Shaner Solutions’ reasonable out-of-pocket expenses. The Company believes that the amount charged by Shaner Solutions is comparable to rates obtainable at an arm’s length basis in the State College, Pennsylvania area for similar services. See Note 11: Subsequent Events.

Rex Operating leases approximately 5,270 square feet of office space from Shaner Brothers, LLC, a Delaware limited liability company controlled by Lance T. Shaner (“Shaner Brothers”). This office space is located at the Company’s current headquarters at 1975 Waddle Road, State College, Pennsylvania. Rex Operating leases this office space pursuant to a written lease agreement that provides for an initial term of three years beginning on September 1, 2006 and expiring on August 31, 2009. The lease agreement requires the payment of rent in the amount of $7,908 per month, subject to adjustment on each anniversary date of the lease in accordance with the percentage of increase in the Consumer Price Index for the U.S. for Urban Consumers (CPI-U) for the preceding year (the “CPI Adjustment”). The monthly rent is also subject to adjustment in the form of additional monthly rent which is calculated annually and equal to the percentage of increase of Shaner Brother’s costs for taxes, insurance premiums and operating expenses for the previous year (the “Additional Monthly Rent”). The annual monthly rent adjustment resulting from the CPI Adjustment and Additional Monthly Rent may not in the aggregate exceed a three percent increase over the prior lease year. Under the terms of the lease, Rex Operating is responsible for certain costs relating to the interior construction of the building and the payment of all utilities, cleaning expenses, maintenance and other related costs and expenses of the building resulting from the Company’s operation, use and occupancy of the premises. Following the expiration of the initial term, Rex Operating may renew the lease for up to 3 one-year extensions upon written notice to Shaner Brothers at least 120 days, but no more than 6 months, prior to the expiration of the current term. The Company believes that the terms of this lease are comparable to terms that could be obtained at an arms’ length basis in the State College, Pennsylvania area for leases of similar office space.

Rex Operating has an oral month-to-month agreement with Charlie Brown Air Corp., a New York corporation owned by Lance T. Shaner (“Charlie Brown”), regarding the use of two airplanes owned by Charlie Brown. Under Rex Operating’s agreement with Charlie Brown, Rex Operating pays a monthly fee for the right to use the airplanes equal to its percentage (based upon the total number of hours of use of the airplanes by the Company) of the monthly fixed costs for the airplane, plus a variable per hour flight rate of $1,350 per hour. The Company believes that the terms of this agreement are comparable to terms that could be obtained at an arms’ length basis in the State College, Pennsylvania area for similar private aircraft services.

9. PARTNERSHIP REDEMPTION

New Albany

On March 12, 2007, New Albany entered into an Extension Agreement with its 50.0% member, Baseline Oil & Gas Corp. (“Baseline”). Under the terms of the Extension Agreement, Baseline was granted a one week extension to March 16, 2007 to pay a mandatory capital call issued by New Albany to Baseline in the amount of $492,424. In addition, the Extension Agreement provided that in the event Baseline paid New Albany an additional $1,729,033 in outstanding capital calls by March 16, 2007, New Albany would redeem Baseline’s 50.0% membership interest in New Albany pursuant to the terms of a mutually agreed upon redemption agreement. Under the terms of the form of redemption agreement, New Albany would agree that in exchange for

F-35

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

the redemption of Baseline’s 50.0% membership interest in New Albany, New Albany would assign 50.0% of its assets, including its leasehold mineral interests, to Baseline. The Extension Agreement provided that in the event that Baseline failed to pay all outstanding capital calls by March 16, 2007, New Albany, and its non-defaulting members, would be entitled to exercise the rights set forth in Section 3.3(a) of New Albany’s limited liability company agreement dated November 25, 2005. Section 3.3(a) provides that in the event a member fails to pay certain mandatory capital calls issued by the managing member of New Albany, New Albany may permit other non-defaulting members to contribute the amount owed by the defaulting member as an additional capital contribution to New Albany. In such event, the membership interests of all members of New Albany will be adjusted pursuant to a formula, the numerator of which is the member’s total capital contributions to New Albany, and the denominator of which is the sum of all members’ total capital contributions to New Albany. The Extension Agreement further provided that in the event that Baseline’s membership interest in New Albany was reduced in the manner set forth above due to its failure to pay all of the outstanding capital calls, New Albany, under the terms of the Redemption Agreement, must immediately thereafter redeem Baseline’s interest in New Albany in exchange for the assignment to Baseline of an interest in all of New Albany’s assets equal to Baseline’s then reduced membership interest.

On March 16, 2007, Baseline paid to New Albany $300,000 of the outstanding capital calls owed to New Albany, leaving an unpaid capital call balance of $1,921,457. Immediately thereafter, in accordance with the terms of the Extension Agreement and Section 3.3.(a) of New Albany’s limited liability company agreement, Baseline’s membership interest in New Albany was reduced from 50.0% to 40.42%. Baseline and New Albany then entered into a redemption agreement providing that Baseline’s membership interest in New Albany was redeemed in exchange for an assignment by New Albany to Baseline of a 40.42% interest in all of New Albany’s assets, including its oil and gas leasehold interests. The value of the redemption was approximately $8.0 million. On March 16, 2007, pursuant to Section 3.3(a) of New Albany’s limited liability company agreement, Rex II elected to pay $3,156,600 to New Albany in satisfaction of its outstanding capital calls, as well as the unpaid outstanding capital calls of Baseline, Rex Energy Wabash, LLC, Shaner & Hulburt Capital Partners Limited Partnership and Lance T. Shaner. In accordance with Section 3.3(a) of New Albany’s limited liability company agreement, the membership interests of the members were thereafter adjusted to reflect the additional capital contributions made by Rex II on behalf of Baseline, Rex Energy Wabash, LLC, Shaner & Hulburt Capital Partners Limited Partnership and Lance T. Shaner, and the redemption of Baseline’s 40.42% membership interest. Following such adjustments, Rex II’s membership interest in New Albany was increased from 26.833% to 45.04%, Rex Energy Wabash, LLC’s membership interest was increased from 0.78% to 1.31%, Lance T. Shaner’s membership interest was increased from 17.93% to 30.09%, Shaner & Hulburt Capital Partners Limited Partner’s membership interest was increased from 2.94% to 4.93% and Douglas Oil & Gas’s membership interest was increased from 11.10% to 18.63%.

10. LITIGATION

PennTex Illinois and Rex Operating—EPA Matter

In September 2006, the United States Department of Justice (“U.S. DOJ”) and the United States Environmental Protection Agency (“U.S. EPA”) initiated an enforcement action against PennTex Illinois and Rex Operating seeking mandatory injunctive relief and potential civil penalties based on allegations that the companies were violating the Clean Air Act in connection with the release of hydrogen sulfide (H2S) gas and other volatile organic compounds (“VOC’s”) in the course of the companies’ oil operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. The companies’ senior management and representatives of the U.S.

F-36

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

EPA, U.S. DOJ, Illinois Environmental Protection Agency (“Illinois EPA”) and the Agency for Toxic Substances and Disease Registry (“ATSDR”) attended a meeting at the offices of the U.S. EPA in Chicago, Illinois on September 7, 2006, to discuss matters relating to the enforcement action. This meeting had been preceded by certain monitoring of air emissions in the areas surrounding Bridgeport, Illinois and Petrolia, Illinois that the U.S. EPA and ATSDR had conducted in May 2006.

As a result of the initial meeting with the government on September 7, 2006, and certain subsequent meetings and communications between the companies’ senior management and the U.S. EPA and U.S. DOJ, PennTex Illinois and Rex Operating executed a non-binding agreement in principle with the U.S. EPA effective October 24, 2006. In the agreement in principle, PennTex Illinois and Rex Operating agreed to develop and carry out a written response plan designed to further reduce possible emissions of H2S and VOC’s from the companies’ oil wells and facilities in the Lawrence Field that are closest to populated areas. The companies agreed to operate and maintain the control measures described in the response plan in accordance with a written operations and maintenance plan to be developed by the companies and approved by the U.S. EPA. The agreement in principle also required PennTex Illinois and Rex Operating to evaluate the effectiveness of the control measures in the Lawrence Field installed pursuant to the response plan through a monitoring program, and required the companies to evaluate the need for additional control measures at other facilities within the Lawrence Field within 60 days. PennTex Illinois and Rex Operating also agreed to present to the U.S. EPA any recommendations for further action the companies might develop based upon their observations of the effectiveness of the control measures. PennTex Illinois and Rex Operating and the U.S. EPA each agreed that they would use their best efforts to negotiate a proposed final settlement agreement that would resolve the government’s enforcement action.

The senior management of PennTex Illinois and Rex Operating and the U.S. EPA and U.S. DOJ negotiated the terms of a comprehensive consent decree in which PennTex Illinois and Rex Operating, without any admission of wrongdoing or liability and without any agreement to pay any civil fine or penalty, would agree to install certain control measures and to implement certain operating and maintenance procedures regarding the companies’ oil operations in the Lawrence Field. Under the terms of the proposed consent decree, PennTex Illinois and Rex Operating would also agree to establish a monitoring protocol that would be designed to facilitate the reduction of possible emissions of H2S and VOC’s from the companies’ operations near Bridgeport, Illinois and Petrolia, Illinois. Any proposed consent decree will ultimately require the approval of a court of proper jurisdiction.

PennTex Illinois and Rex Operating intend to vigorously defend themselves in this matter. In the event that the consent decree is not ultimately approved by a court of proper jurisdiction, the Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. See Note 11: Subsequent Events.

PennTex Illinois and Rex Operating—Leib Case

PennTex Illinois and Rex Operating are defendants in a putative class action lawsuit that has been filed in the United States District Court for the Southern District of Illinois, Cause Number 3:06-CV-00802-JPG-CJP, styled “Julia Leib, et al. v. Rex Energy Operating Corp., et al.” This action was commenced on October 17, 2006, by plaintiffs, Julia Leib and Lisa Thompson, individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport, Illinois and Petrolia, Illinois. The complaint asserts that the operation of oil wells that are controlled,

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

owned or operated by PennTex Illinois and Rex Operating has resulted in “serious contamination” of the class area with H2S. The complaint asserts several causes of action, including violation of the Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct. The complaint seeks, among other things, injunctive relief under the Illinois Environmental Protection Act and Illinois common law, compensatory and other damages, punitive damages, and attorneys’ fees and costs. In addition, the complaint seeks the creation of a court-supervised, defendant-financed fund to pay for medical monitoring for the plaintiffs and others in the class area.

On November 14, 2006, PennTex Illinois and Rex Operating filed a joint answer to the complaint specifically denying virtually all of the allegations in the complaint and asserting affirmative defenses thereto. On December 20, 2006, the plaintiffs filed a motion for class certification requesting that the court certify the case as a class action. PennTex Illinois and Rex Operating intend to vigorously oppose the plaintiffs’ motion for certification of the case as a class action.

Pursuant to the terms of a pollution liability policy with Federal Insurance Company, PennTex Illinois and Rex Operating have insurance coverage for possible damages relating to claims made in this lawsuit for up to $1,000,000. In addition, in accordance with the terms of the pollution liability policy, Federal Insurance Company has agreed to conduct the companies’ defense in this lawsuit at the insurer’s expense. Under the terms of a written agreement with PennTex Illinois and Rex Operating, Federal Insurance Company has agreed to pay a substantial portion of the companies’ costs and expenses relating to the defense of this lawsuit, including attorneys’ fees. Under the terms of the agreement, PennTex Illinois and Rex Operating are required to pay the costs and expenses relating to the defense in excess of the amounts payable by Federal Insurance Company.

PennTex Illinois and Rex Operating intend to vigorously defend against the claims that have been asserted against the companies in this lawsuit. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or the range of potential loss should the outcome be unfavorable.

PennTex Resources

PennTex Resources is a party to an arbitration panel convened by the American Arbitration Association in Houston, Texas, Cause Number 70 180 Y 00437 06, styled “PennTex Resources, L.P. And Lance T. Shaner, Claimants v. ERG Illinois Holdings, Inc. And Scott Y. Wood, Respondents.” This is a binding arbitration proceeding that was commenced on June 21, 2006, by PennTex Resources and Lance T. Shaner (“Shaner”) against ERG Illinois Holdings, Inc. (“ERG Holdings”) and Scott Y. Wood (“Wood”) pursuant to the dispute resolution provisions of a stock purchase agreement that was entered into in January 2005 by Wood’s company, ERG Holdings, as “Seller” and PennTex Resources, as “Buyer” (the “2005 Stock Purchase Agreement”).

The principal claim in the arbitration proceeding is PennTex Resources and Shaner’s claim that ERG Holdings and Wood should be ordered to comply with a “release obligation” contained in the 2005 Stock Purchase Agreement that requires Wood, under certain designated circumstances, to dismiss or release the individual claims that he is prosecuting against Tsar Energy II, LLC (“Tsar”) and Richard M. Cheatham (“Cheatham”) in a lawsuit in the 334th Judicial District Court of Harris County, Texas, cause number 2004-39584, styled “ERG Illinois, Inc. And Scott Y. Wood v. Tsar Energy II, LLC And Richard M. Cheatham (the “Tsar Case”). The dispute in the Tsar Case centers around overhead fees charged by PennTex Illinois as operator of jointly-owned oil producing properties located in Illinois and Indiana in which PennTex Resources owns a 25.0%

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FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

working interest (the “Illinois and Indiana Properties”). Tsar then owned a 49.0% non-operator working interest in the subject properties. PennTex Illinois (then known as ERG Illinois, Inc.) and its former owner, Wood, commenced this litigation in July 2004, by filing a petition against Tsar and its president, Cheatham, seeking, among other things, a declaratory judgment that PennTex Illinois, as the operator of the subject properties, was entitled to charge Tsar and the other non-operators their proportionate shares of a fixed monthly overhead charge of $300 for each producing well located within the North Lawrence Unit portion of the properties pursuant to the terms of a operating agreement relating to such unit. PennTex Resources became obligated to file this arbitration proceeding seeking to enforce Wood’s “release obligation” under the 2005 Stock Purchase Agreement, and to prosecute such proceeding diligently without compromise until final award, by reason of an agreement that PennTex Illinois and PennTex Resources entered into on March 2, 2006 with Tsar and Cheatham in order to resolve certain procedural issues relating to the Tsar Case.

PennTex Resources and/or Shaner have also filed the following additional claims in the arbitration proceeding in which PennTex Resources or Shaner seek an award of money damages from ERG Holdings: (a) Shaner, as the assignee of the “Buyer” under the 2005 Stock Purchase Agreement, has filed a claim against ERG Holdings, as the “Seller” under the 2005 Stock Purchase Agreement, seeking an award of $383,760, plus pre-award interest and attorneys’ fees, based on ERG Holdings’ alleged breach of its obligation to make an appropriate post-closing purchase price adjustment as required under the terms of Section 2.2(c)(D) of the 2005 Stock Purchase Agreement; (b) PennTex Resources has filed a claim against ERG Holdings seeking an award of approximately $20,000, plus pre-award interest and attorneys’ fees, based on ERG Holdings’ alleged breach of a contractual obligation, allegedly arising under Section 9.4(d) of the 2005 Stock Purchase Agreement, to return the original and all copies of a letter a credit posted by the Buyer under that agreement to secure its indemnity obligations described in Section 9.4, which breach is alleged to have wrongfully caused PennTex Resources to have had to unnecessarily incur an annual renewal fee to keep such letter of credit in force so as to prevent ERG Holdings from having the right to draw on it (PennTex Resources’ claim in this regard also seeks equitable and injunctive relief that would declare the letter of credit void and restrain ERG Holdings from attempting to draw on it.); and (c) PennTex Resources has filed a claim against ERG Holdings seeking an award of approximately $23,500 (which PennTex Resources believes is likely to be revised downward to approximately $2,500), plus pre-award interest and attorneys’ fees, based on ERG Holdings’ alleged breach of its obligation to make an appropriate pre-closing purchase price adjustment as required under the terms of Section 2.2(c)(C) of the 2005 Stock Purchase Agreement by failing to reflect in its final closing statement an existing liability owed to the owners of a net profits interest relating to certain leases within the Illinois and Indiana Properties.

In its pleading filed on January 22, 2007, ERG Holding and Wood have denied all of the PennTex Resources’ and Shaner’s claims, and ERG Holdings has asserted a counterclaim against PennTex Resources based on its previously-asserted claim that it is entitled to a post-closing adjustment in the purchase price in its favor in the amount of $182,864.97. The arbitration panel of the American Arbitration Association has scheduled a final hearing in the arbitration proceeding for June 25-26, 2007.

PennTex Resources and Shaner intend to vigorously prosecute all of the claims asserted in the arbitration proceedings. PennTex Resources and Shaner will also vigorously defend ERG Holdings’ counterclaim seeking an award that would result in a final purchase price closing adjustment in the amount of $182,865 in favor of the “Seller” under the 2005 Stock Purchase Agreement. PennTex Resources is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter. See Note 11: Subsequent Events.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

11. SUBSEQUENT EVENTS

PennTex Illinois and Rex Operating

In April 2007, PennTex Illinois, Rex Operating and the U.S. EPA and U.S. DOJ executed a comprehensive consent decree in which PennTex Illinois and Rex Operating, without any admission of wrongdoing or liability and without any agreement to pay any civil fine or penalty, agreed to install certain control measures and to implement certain operating and maintenance procedures in the Lawrence Field. Under the terms of the proposed consent decree, PennTex Illinois and Rex Operating agreed to establish a monitoring protocol that would be designed to facilitate the reduction of possible emissions of H2S and VOCs from PennTex Illinois’ operations near Bridgeport and Petrolia. PennTex Illinois and Rex Energy Operating estimate the incremental costs that will be incurred in order to comply with the provisions of the consent decree will be approximately $1.4 million, all of which will be incurred in 2007. A notice regarding the proposed consent decree was published in the Federal Register on April 19, 2007. The published notice of the proposed consent decree solicited public comments on the terms of the consent decree for a 30 day period expiring on May 21, 2007. The United States did not receive any comments on the proposed consent decree during the public comment period. On June 1, 2007, the United States filed a motion for the approval and entry of the proposed consent decree with the United States District Court for the Southern District of Illinois. On June 6, 2007, the court granted the United States’ motion for approval and entry of the proposed consent decree, thereby resolving the enforcement action according to the terms described in the consent decree. The consent decree does not require PennTex Illinois or Rex Operating to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree.

PennTex Resources

On April 3, 2007, ERG Holdings and Wood filed a supplement to their counterclaim against PennTex Resources and Shaner in the arbitration panel proceeding conveyed by the American Arbitration Association. See Note 10: Litigation. In the supplement, ERG Holdings and Wood seek an award of an amount equal to all expenses and costs incurred in the defense of ERG Holdings and Wood in the Tsar Case and the prosecution of Wood’s claims in the same case. As of February 28, 2007, ERG and Wood claim $92,430 in attorney’s fees and related costs and expenses. On April 6, 2007, PennTex Resources and Shaner filed a motion with the arbitration panel to strike ERG Holdings’ and Wood’s supplemental counterclaim on the grounds that it was untimely under the parties agreed upon scheduling order and was filed in disregard of the provisions of the 2005 Stock Purchase Agreement and the Commercial Arbitration Rules of the American Arbitration Association. In addition, PennTex Resources and Shaner moved that the supplement be stricken in order to prevent ERG Holdings and Wood from achieving an unfair advantage in the arbitration by reason of their failure to follow agreed-upon and applicable procedures.

On April 27, 2007, a majority of the arbitration panel ruled to strike PennTex Resources’ and Shaner’s motion to strike the supplement to ERG Holdings’ and Wood’s counterclaim. PennTex Resources and Shaner will vigorously defend the attorney fees claim asserted in the supplement to ERG Holdings’ and Woods’ counterclaim. PennTex Resources is unable to express an opinion with respect to the likelihood of an unfavorable outcome in this matter. However, given that it is unlikely that the arbitration panel would allow either party to amend their respective claims to increase the amount sought therein, PennTex Resources believes that the amount of potential loss to PennTex Resources should the outcome be unfavorable would be no more than $275,295, plus the amount of any attorney’s fees and costs incurred by ERG Holdings and Wood in the Tsar

F-40

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

Case from February 28, 2007 to the date of any unfavorable arbitration award. The arbitration panel held a final hearing in the arbitration proceeding on June 25 and 26, 2007. A final ruling of the arbitration panel is expected to be issued sometime in July 2007.

Rex Operating

On April 10, 2007, Rex Operating terminated its oral month-to-month administrative services agreement with Shaner Solutions. See Note 8: Related Party Transactions. In conjunction with this termination, Rex Operating entered into an IT Consultation and Support Services Agreement, a Service Provider Agreement and a Tax Return Engagement Letter Agreement with Shaner Hotel Group Limited Partnership, a Delaware limited partnership controlled by Lance T. Shaner (“Shaner Hotel”). Pursuant to the IT Consultation and Support Services Agreement, Shaner Hotel agreed to provide Rex Operating with telecommunication, computer system and network administration, and information technology consultation services. Fees for the services provided under this agreement range from $55.00 to $125.00 per hour based upon the type and level of service provided. The agreement continues until it is terminated by either party upon ninety (90) days advance written notice. Pursuant to the Service Provider Agreement, Shaner Hotel agreed to provide Rex Operating with certain clerical and administrative support services in connection with the management and administration of Rex Operating’s 401(k) retirement plan and its employee health and welfare benefit plans. Under the agreement, Rex Operating pays a fee of $95.00 per hour for any services performed by Shaner Hotel’s Benefits Manager and a fee of $55.00 per hour for services provided by other members of Shaner Hotel’s benefits department. The term of the Service Provider Agreement is one year, however, either party may terminate the agreement upon ninety (90) days advance written notice. Pursuant to the Tax Return Engagement Letter Agreement, Shaner Hotel agreed to provide Rex Operating and the Founding Companies with certain tax planning and tax return preparation services. Fees for the services provided under this agreement range from $100.00 to $155.00 per hour based upon the tax expertise of the particular service provider. The agreement continues until it is terminated by either party upon ninety (90) days advance written notice.

On June 21, 2007, Rex Operating obtained a 24.75% limited partnership interest in Charlie Brown II Limited Partnership, a Delaware limited partnership (“Charlie Brown II”), and a 25% membership interest in its general partner, L&B Air LLC, a Delaware limited liability company (“L&B Air”). Charlie Brown II has ordered and agreed to purchase a 500 Eclipse Airplane for $1,700,000. The airplane is scheduled to be delivered from the manufacturer to Charlie Brown II in January of 2008. Shaner Hotel Group Limited Partnership, a Delaware limited partnership controlled by Mr. Shaner (“Shaner Hotel Group”), owns a 24.65% limited partnership interest in Charlie Brown II and a 25% membership interest in L&B Air, and Charlie Brown, an entity owned and controlled by Mr. Shaner, owns a .1% membership interest in L&B Air. The remaining 49.50% limited partnership interest in Charlie Brown II and 50% interest in L&B Air is owned by an unrelated third party. On June 21, 2007, Rex Operating made capital contributions to Charlie Brown II and L&B Air in the amount of $49,500 and $500, respectively. To fund these capital contributions, Rex Operating borrowed $50,000 from Mr. Shaner. This loan is evidenced by a promissory note dated June 21, 2007 and bears interest at the rate of 7% per annum. The promissory note is payable upon the demand of Mr. Shaner and may be prepaid in whole or in part without penalty.

On June 21, 2007, Charlie Brown II and Charlie Brown entered into a First Amended and Restated Aircraft Joint Ownership and Management Agreement. Pursuant to this agreement, Charlie Brown agreed to provide certain aircraft management services, such as routine and scheduled maintenance, flight crew training, cleaning, inspections and flight operations and scheduling of the aircraft. In addition, Charlie Brown agreed to provide a

F-41

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

flight crew for the operating of the aircraft and storage space in its hanger for storage of the aircraft. In exchange for these services, Charlie Brown II agreed to pay its proportionate share of Charlie Brown’s fixed costs, including crew, hanger and insurance costs, and a per hour flight charge to be determined by Charlie Brown consistent with current local market rates charged by similar flight operation companies.

The business affairs of Charlie Brown II are managed by its general partner, L&B Air. L&B Air is managed by three managers, appointed by each of its three members. Rex Operating designated Benjamin W. Hulburt, its Chief Executive Officer, as the manager representing the company’s membership interest. Actions of L&B Air must be approved by a majority of the interest percentages of the managers. Each manager votes in matters before the company in accordance the membership interest percentage of the member that appointed the manager. Certain events, such as the sale by a member of its interest, the merger or consolidation of L&B Air or Charlie Brown II, the filing of bankruptcy, or the sale of the airplane owned by Charlie Brown II, require the consent of all managers. The consent of all limited partners of Charlie Brown II is required before the partnership may change or terminate the management agreement with Charlie Brown, incur any indebtedness, sell substantially all of the partnership’s assets or the sale the airplane owned by the partnership. In the event that the limited partners are unable to unanimously agree upon any of these matters within 10 days of the proposal of any such matter, an “impasse” may be declared, and the airplane will be sold by the partnership.

On June 21, 2007, Charlie Brown II borrowed $1,530,000 from Graystone Bank. Proceeds from this loan were used to reimburse Mr. Shaner and an unrelated third party for a deposit they paid on behalf of Charlie Brown II in connection with the purchase of the 500 Eclipse airplane. The loan matures on June 21, 2017 and bears interest at a rate of LIBOR plus 2.5%. The loan requires payments of interest only for the first three months of the loan. Thereafter, Charlie Brown II is required to make monthly payments of principal and interest utilizing an amortization period of 180 months. The loan to Charlie Brown II was guaranteed by Mr. Shaner and the unrelated third party.

Rex II

On April 19, 2007, Rex II acquired a 52.375%, and 83.707% working interest in 2 oil and gas leases covering properties located in Concho County, Texas for $890,000. The acquisition included interests in 13 producing oil wells and related infrastructure and equipment. The interests were purchased from various working interest owners, including the operator of the properties, Ultra Oil & Gas Inc. Ultra Oil & Gas Inc. acted as agent for the various sellers. The effective date of the acquisition was January 1, 2007.

On May 24, 2007, Rex II acquired a forty percent (40.0%) working interest in certain undeveloped oil and gas leases covering approximately 17,981 net acres located in Knox, Daviess, Sullivan and Greene Counties in the State of Indiana. The interests were acquired from HAREXCO, Inc., an Illinois corporation doing business in the State of Indiana under the assumed name of Harris Energy Company (“Harris Energy”), for a purchase price of $1,078,838. In connection with this sale, Harris Energy reserved a four percent (4.0%) of forty percent (40.0%) overriding royalty interest in the conveyed properties and a ten percent (10.0%) of forty percent (40.0%) back-in-after-payout working interest in the first five net wells drilled on the acquired properties or any other properties which are subsequently acquired by Rex II from Harris Energy. In connection with the closing, Rex II and Harris Energy entered into an exploration agreement, wherein the parties created an area of mutual interest in certain areas of the above counties, and a joint operating agreement, wherein Rex II was appointed the operator of the covered properties. Rex II also agreed to purchase from Harris Energy a forty percent (40.0%) working interest in certain oil and gas leasehold interests covering up to 5,878 net acres located in Knox

F-42

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(Unaudited)

County, Indiana. Pursuant to the agreement between the parties, Rex II is obligated to purchase an interest in only those oil and gas leases which are acquired by Harris Energy on or before August 22, 2007. The purchase price for the interest in these leases is equal to forty percent (40.0%) of the product of $100.00 and the number of net leasehold acres assigned to Rex II on the closing date. In the event that Rex II purchases an interest in any of these leases, Harris Energy will also be entitled to reserve and retain the same overriding royalty interest and the back-in-after-payout working interest described above.

12. COMBINED FINANCIAL STATEMENTS AND SCHEDULES

As described in Note 1, the combined financial statements include the 13 entities that comprise the Founding Companies of Rex Energy Corporation. The following information presents combining financial statements, which include the individual company information and the eliminations necessary to combine the Founding Companies of Rex Energy Corporation.

F-43

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(unaudited)

CONSOLIDATING BALANCE SHEET

March 31, 2007

	PennTex Resources Illinois, Inc.			PennTex Resources, LP			Rex Energy Royalties, LP			Douglas Oil & Gas, LP			Douglas Westmoreland, LP			Midland Exploration, LP			Rex Energy, LP
ASSETS
Current Assets
Cash and Cash Equivalents	$	7,656		$	0		$	0		$	0		$	0		$	16,344		$	20,493
Accounts Receivable		1,372,821			715,699			0			817,042			762,565			50,679			4,821
Related Party Receivable		1,412,931			399,197			128,194			338,768			0			0			73,792
Short-Term Derivative Instruments		0			0			0			35,035			35,035			0			0
Inventory, Prepaid Expenses and Other		1,172,238			83,194			0			129,446			6,027			536			0
Total Current Assets		3,965,646			1,198,090			128,194			1,320,291			803,627			67,559			99,106
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		9,199,001			6,178,277			1,500,000			13,524,774			5,798,045			692,797			186,751
Unevaluated Oil and Gas Properties		0			0			0			151,310			0			0			0
Other Property and Equipment		608,975			0			0			680,962			40,104			0			0
Wells in Progress		99,399			9,592			0			0			0			0			0
Pipelines		0			0			0			1,530,969			271,178			0			0
Total Property and Equipment		9,907,375			6,187,869			1,500,000			15,888,015			6,109,327			692,797			186,751
Less: Accumulated Depreciation, Depletion and Amortization		(1,900,378	)		(1,673,526	)		(285,904	)		(6,769,256	)		(1,214,943	)		(391,125	)		(45,208	)
Net Property and Equipment		8,006,997			4,514,343			1,214,096			9,118,759			4,894,384			301,672			141,543
Other Assets
Other Assets—Net		0			206,105			0			1,889,069			0			0			2,177,061
Long-Term Derivative Instruments		0			0			0			0			0			0			0
Total Other Assets		0			206,105			0			1,889,069			0			0			2,177,061
Total Assets	$	11,972,643		$	5,918,538		$	1,342,290		$	12,328,119		$	5,698,011		$	369,231		$	2,417,710
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable and Accrued Expenses	$	2,542,423			792,524		$	19,143		$	310,209		$	224,877		$	80,809		$	(727	)
Short-Term Derivative Instruments		1,811,372			519,557			25,149			0			0			0			0
Accrued Distributions		0			0			0			0			0			0			0
Lines of Credit		0			0			0			0			0			0			0
Current Portion of Long-Term Debt		68,271			0			0			6,012,843			3,005,036			0			0
Related Party Payable		399,197			1,601,817			0			392,191			432,943			59,572			0
Total Current Liabilities		4,821,263			2,913,898			44,292			6,715,243			3,662,856			140,381			(727	)
Long-Term Liabilities
Long-Term Debt		4,700,000			12,644,536			0			0			0			0			0
Other Loans and Notes Payable—Long-Term Portion		148,923			0			0			69,999			13,580			0			0
Long-Term Derivative Instruments		223,073			394,162			0			214,254			214,254			0			0
Participation Liability		0			0			0			0			2,141,109			0			0
Other Deposits and Liabilities		0			0			0			322,046			0			0			0
Asset Retirement Obligation		943,068			908,394			0			236,585			135,797			8,514			0
Total Long-Term Liabilities		6,015,064			13,947,092			0			842,884			2,504,740			8,514			0
Total Liabilities		10,836,327			16,860,990			44,292			7,558,127			6,167,596			148,895			(727	)
Minority Interests		0			0			1,241,309			3,684,646			(488,478	)		211,023			1,879,325
Owners’ Equity
Common Stock		1,000			0			0			0			0			0			0
Additional Paid-In Capital		1,460,000			0			0			0			0			0			0
Accumulated Stockholders’ Deficit		(324,684	)		0			0			0			0			0			0
Partners’ and Members’ Equity (Deficit)		0			(10,942,452	)		56,689			1,085,346			18,893			9,313			539,112
Total Owners’ Equity (Deficit)		1,136,316			(10,942,452	)		56,689			1,085,346			18,893			9,313			539,112
Total Liabilities, Minority Interests and Owners’ Equity (Deficit)	$	11,972,643		$	5,918,538		$	1,342,290		$	12,328,119		$	5,698,011		$	369,231		$	2,417,710

F-44

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(unaudited)

CONSOLIDATING BALANCE SHEET

March 31, 2007

	Rex Energy II, LP			Rex Energy II Alpha, LP			Rex Energy III, LLC			Rex Energy IV, LLC			New Albany— Indiana, LLC		Rex Energy Operating Corp.			Eliminations			Total
ASSETS
Current Assets
Cash and Cash Equivalents	$	34,001		$	4,328		$	50,757		$	404,947		$	1,052,737	$	0		$	0		$	1,591,263
Accounts Receivable		1,096,832			1,557			667,452			1,417,467			6,671		12,879			0			6,926,485
Related Party Receivable		1,639,291			26,107			0			0			3,322,049		177,712			(7,384,820	)		133,221
Short-Term Derivative Instruments		0			0			62,022			0			0		0			0			132,092
Inventory, Prepaid Expenses and Other		136,614			1,449			337,314			164,627			0		122,665			0			2,154,110
Total Current Assets		2,906,738			33,441			1,117,545			1,987,041			4,381,457		313,256			(7,384,820	)		10,937,171
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		29,589,190			1,209,988			24,626,224			38,581,044			0		0			0			131,086,091
Unevaluated Oil and Gas Properties		1,682,779			1,069			203,606			0			7,895,473		0			0			9,934,237
Other Property and Equipment		9,256			0			1,163,000			0			344,541		1,275,699			0			4,122,537
Wells in Progress		0			0			0			0			1,756,595		0			0			1,865,586
Pipelines		0			0			0			0			0		0			0			1,802,147
Total Property and Equipment		31,281,225			1,211,057			25,992,830			38,581,044			9,996,609		1,275,699			0			148,810,598
Less: Accumulated Depreciation, Depletion and Amortization		(3,723,221	)		(189,234	)		(2,748,166	)		(2,079,184	)		0		(196,959	)		0			(21,217,104	)
Net Property and Equipment		27,558,004			1,021,823			23,244,664			36,501,860			9,996,609		1,078,740			0			127,593,494
Other Assets
Other Assets—Net		5,560,303			0			347,172			300,000			0		46,747			(9,286,461	)		1,239,996
Long-Term Derivative Instruments		0			0			0			0			0		0			0			0
Total Other Assets		5,560,303			0			347,172			300,000			0		46,747			(9,286,461	)		1,239,996
Total Assets	$	36,025,045		$	1,055,264		$	24,709,381		$	38,788,901		$	14,378,066	$	1,438,743		$	(16,671,281	)	$	139,770,661
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable and Accrued Expenses	$	773,127		$	402		$	230,438		$	852,211		$	1,478,974	$	986,881		$	0		$	8,291,291
Short-Term Derivative Instruments		312,184			1,877			0			715,165			0		0			(180,241	)		3,205,063
Accrued Distributions		0			0			0			0			0		0			0			0
Lines of Credit		0			0			0			38,630,634			0		0			0			38,630,634
Current Portion of Long-Term Debt		0			0			2,475,000			0			0		0			0			11,561,150
Related Party Payable		2,929,857			0			501,326			8,190			1,059,725		0			(7,384,818	)		0
Total Current Liabilities		4,015,168			2,279			3,206,764			40,206,200			2,538,699		986,881			(7,565,059	)		61,688,138
Long-Term Liabilities
Long-Term Debt		7,442,027			0			17,525,000			0			0		0			0			42,311,563
Other Loans and Notes Payable—Long-Term Portion		0			0			0			0			0		539,998			0			772,500
Long-Term Derivative Instruments		373,282			18,493			109,831			1,894,386			0		0			180,241			3,621,976
Participation Liability		0			0			0			0			0		0			0			2,141,109
Other Deposits and Liabilities		0			0			0			0			0		71,172			0			393,218
Asset Retirement Obligation		1,056,152			38,943			669,418			1,659,141			10,267		0			0			5,666,279
Total Long-Term Liabilities		8,871,461			57,436			18,304,249			3,553,527			10,267		611,170			180,241			54,906,645
Total Liabilities		12,886,629			59,715			21,511,013			43,759,727			2,548,966		1,598,051			(7,384,818	)		116,594,783
Minority Interests		20,512,507			995,549			106,126			(2,485,413	)		7,435,502		(63,730	)		(7,629,256	)		25,399,110
Owners’ Equity
Common Stock		0			0			0			0			0		60			0			1,060
Additional Paid-In Capital		0			0			0			0			0		0			0			1,460,000
Accumulated Stockholders’ Deficit		0			0			0			0			0		(95,638	)		0			(420,322	)
Partners’ and Members’ Equity (Deficit)		2,625,909			0			3,092,242			(2,485,413	)		4,393,598		0			(1,657,207	)		(3,263,970	)
Total Owners’ Equity (Deficit)		2,625,909			0			3,092,242			(2,485,413	)		4,393,598		(95,578	)		(1,657,207	)		(2,223,232	)
Total Liabilities, Minority Interests and Owners’ Equity (Deficit)	$	36,025,045		$	1,055,264		$	24,709,381		$	38,788,901		$	14,378,066	$	1,438,743		$	(16,671,281	)	$	139,770,661

F-45

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR QUARTERLY PERIOD ENDED MARCH 31, 2007

(unaudited)

CONSOLIDATING BALANCE SHEET

December 31, 2006

	PennTex Resources Illinois, Inc.			PennTex Resources, LP			Rex Energy Royalties, LP			Douglas Oil & Gas, LP			Douglas Westmoreland, LP			Midland Exploration, LP			Rex Energy, LP
ASSETS
Current Assets
Cash and Cash Equivalents	$	6,951		$	27,805		$	1,482		$	0		$	0		$	64,245		$	71,467
Restricted Cash		0			0			0			0			0			0			0
Accounts Receivable		917,084			795,508			0			843,505			672,686			80,231			5,225
Related Party Receivable		1,580,098			399,496			66,315			675,268			0			0			12,307
Short-Term Derivative Instruments		0			0			0			401,367			401,367			0			0
Inventory, Prepaid Expenses and Other		606,744			87,466			0			95,867			0			2,088			0
Total Current Assets		3,110,877			1,310,275			67,797			2,016,007			1,074,053			146,564			88,999
Property and Equipment
Evaluated Oil and Gas Properties		8,614,317			5,612,267			1,500,000			13,235,006			5,796,901			692,637			186,751
Unevaluated Oil and Gas Properties		0			0			0			140,443			0			0			0
Other Property and Equipment		578,855			0			0			680,962			40,104			0			0
Wells in Progress		80,000			0			0			189,293			0			0			0
Pipelines		0			0			0			1,530,969			233,470			0			0
Total Property and Equipment		9,273,172			5,612,267			1,500,000			15,776,673			6,070,475			692,637			186,751
Less: Accumulated Depreciation, Depletion and Amortization		(1,652,006	)		(1,532,518	)		(258,162	)		(6,520,122	)		(1,024,040	)		(372,565	)		(37,333	)
Net Property and Equipment		7,621,166			4,079,749			1,241,838			9,256,551			5,046,435			320,072			149,418
Other Assets
Other Assets—Net		0			235,549			0			1,444,755			0			0			2,395,963
Long-Term Derivative Instruments		22,746			0			0			0			0			0			0
Total Other Assets		22,746			235,549			0			1,444,755			0			0			2,395,963
Total Assets	$	10,754,789		$	5,625,573		$	1,309,635		$	12,717,313		$	6,120,488		$	466,636		$	2,634,380
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable and Accrued Expenses	$	2,391,343		$	777,858		$	0		$	407,197		$	426,193		$	106,728		$	0
Short-Term Derivative Instruments		2,098,391			873,909			0			0			0			0			0
Accrued Distributions		0			0			0			0			0			102,465			0
Lines of Credit		0			0			0			0			0			0			0
Current Portion of Long-Term Debt		90,330			0			0			21,656			5,036			0			0
Related Party Payable		1,820,000			1,291,201			0			35,705			530,467			43,827			0
Total Current Liabilities		6,400,064			2,942,968			0			464,558			961,696			253,020			0
Long-Term Liabilities
Long-Term Debt		2,300,000			12,644,536			0			5,941,586			3,000,000			0			0
Other Loans and Notes Payable—Long-Term Portion		148,922			0			0			74,765			14,796			0			0
Long-Term Derivative Instruments		0			132,668			0			99,733			99,733			0			0
Participation Liability—Net		0			0			0			0			2,141,109			0			0
Other Liabilities		0			0			0			322,046			0			0			0
Asset Retirement Obligation		920,568			887,569			0			229,677			132,485			8,375			0
Total Long-Term Liabilities		3,369,490			13,664,773			0			6,667,807			5,388,123			8,375			0
Total Liabilities		9,769,554			16,607,741			0			7,132,365			6,349,819			261,395			0
Minority Interests		0			0			1,252,449			4,381,617			(281,140	)		196,311			2,047,180
Owners’ Equity
Common Stock		1,000			0			0			0			0			0			0
Additional Paid-In Capital		1,460,000			0			0			0			0			0			0
Accumulated Stockholders’ (Deficit)		(475,765	)		0			0			0			0			0			0
Partners’ and Members’ Equity (Deficit)		0			(10,982,168	)		57,186			1,203,331			51,809			8,930			587,200
Total Owners’ Equity (Deficit)		985,235			(10,982,168	)		57,186			1,203,331			51,809			8,930			587,200
Total Liabilities, Minority Interests and Owners’ Equity (Deficit)	$	10,754,789		$	5,625,573		$	1,309,635		$	12,717,313		$	6,120,488		$	466,636		$	2,634,380

F-46

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(unaudited)

CONSOLIDATING BALANCE SHEET

December 31, 2006

	Rex Energy II, LP			Rex Energy II Alpha, LP			Rex Energy III, LLC			Rex Energy IV, LLC			New Albany— Indiana, LLC		Rex Energy Operating Corp.			Eliminations			Total
ASSETS
Current Assets
Cash and Cash Equivalents	$	57,164		$	2,606		$	0		$	239,683		$	101,903	$	26,490		$	0		$	599,796
Restricted Cash		0			0			0			0			0		0			0			0
Accounts Receivable		1,220,593			6,447			618,013			1,574,987			0		149,956			0			6,884,235
Related Party Receivable		21,352			36,804			4,878			47,039			94,375		87,026			(3,023,260	)		1,698
Short-Term Derivative Instruments		0			0			456,498			15,633			0		0			0			1,274,865
Inventory, Prepaid Expenses and Other		110,102			1,025			378,554			174,887			0		63,519			0			1,520,252
Total Current Assets		1,409,211			46,882			1,457,943			2,052,229			196,278		326,991			(3,023,260	)		10,280,846
Property and Equipment
Evaluated Oil and Gas Properties		28,928,079			1,207,102			24,166,475			37,430,910			0		0			0			127,370,445
Unevaluated Oil and Gas Properties		1,043,036			1,952			197,664			0			13,186,186		0			0			14,569,281
Other Property and Equipment		9,256			0			1,163,000			0			578,312		1,131,354			0			4,181,843
Wells in Progress		20,300			0			0			0			2,554,888		0			0			2,844,481
Pipelines		0			0			0			0			0		0			0			1,764,439
Total Property and Equipment		30,000,671			1,209,054			25,527,139			37,430,910			16,319,386		1,131,354			0			150,730,489
Less: Accumulated Depreciation, Depletion and Amortization		(3,042,174	)		(159,900	)		(1,933,620	)		(1,064,648	)		0		(117,545	)		0			(17,714,633	)
Net Property and Equipment		26,958,497			1,049,154			23,593,519			36,366,262			16,319,386		1,013,809			0			133,015,856
Other Assets
Other Assets—Net		1,714,297			0			385,746			326,413			0		46,747			(5,377,675	)		1,171,795
Long-Term Derivative Instruments		0			0			120,109			0			0		0			0			142,855
Total Other Assets		1,714,297			0			505,855			326,413			0		46,747			(5,377,675	)		1,314,650
Total Assets	$	30,082,005		$	1,096,036		$	25,557,317		$	38,744,904		$	16,515,664	$	1,387,547		$	(8,400,935	)	$	144,611,352
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable and Accrued Expenses	$	1,020,373		$	402		$	789,541		$	854,115		$	1,050,788	$	511,042		$	0		$	8,335,580
Short-Term Derivative Instruments		5,397			0			0			0			0		0			0			2,977,697
Accrued Distributions		0			0			0			0			0		0			0			102,465
Lines of Credit		0			0			0			37,580,634			0		0			0			37,580,634
Current Portion of Long-Term Debt		0			0			2,475,000			0			0		275,518			0			2,867,540
Related Party Payable		173,246			1,944			484,658			8,877			3,683		449,652			(3,023,260	)		1,820,000
Total Current Liabilities		1,199,016			2,346			3,749,199			38,443,626			1,054,471		1,236,212			(3,023,260	)		53,683,916
Long-Term Liabilities
Long-Term Debt		3,550,149			0			17,525,000			0			0		0			0			44,961,271
Other Loans and Notes Payable—Long-Term Portion		0			0			0			0			0		242,890			0			481,373
Long-Term Derivative Instruments		134,168			10,923			0			1,220,900			0		0			0			1,698,125
Participation Liability—Net		0			0			0			0			0		0			0			2,141,109
Other Liabilities		0			0			0			0			0		83,034			0			405,080
Asset Retirement Obligation		762,893			38,131			652,331			1,619,576			16,877		0			0			5,268,482
Total Long-Term Liabilities		4,447,210			49,054			18,177,331			2,840,476			16,877		325,924			0			54,955,440
Total Liabilities		5,646,226			51,400			21,926,530			41,284,102			1,071,348		1,562,136			(3,023,260	)		108,639,356
Minority Interests		21,663,512			1,044,636			337,471			(1,269,599	)		11,498,791		(69,836	)		(4,212,032	)		36,589,360
Owners’ Equity
Common Stock		0			0			0			0			0		60			0			1,060
Additional Paid-In Capital		0			0			0			0			0		0			0			1,460,000
Accumulated Stockholders’ (Deficit)		0			0			0			0			0		(104,813	)		0			(580,578	)
Partners’ and Members’ Equity (Deficit)		2,772,267			0			3,293,316			(1,269,599	)		3,945,525		0			(1,165,643	)		(1,497,846	)
Total Owners’ Equity (Deficit)		2,772,267			0			3,293,316			(1,269,599	)		3,945,525		(104,753	)		(1,165,643	)		(617,364	)
Total Liabilities, Minority Interests and Owners’ Equity (Deficit)	$	30,082,005		$	1,096,036		$	25,557,317		$	38,744,904		$	16,515,664	$	1,387,547		$	(8,400,935	)	$	144,611,352

F-47

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(unaudited)

CONSOLIDATING STATEMENT OF OPERATIONS

Three Months Ended March 31, 2007

	PennTex Resources Illinois, Inc.			PennTex Resources, LP			Rex Energy Royalties, LP			Douglas Oil & Gas, LP			Douglas Westmoreland, LP			Midland Exploration, LP			Rex Energy, LP
OPERATING REVENUE
Oil and Natural Gas Sales	$	1,995,016		$	1,879,709		$	171,449		$	642,988		$	796,537		$	69,286		$	12,810
Other Operating Revenue		0			0			0			15,144			0			0			0
Realized Gain (Loss) on Hedges		(318,850	)		(478,000	)		0			70,730			70,730			0			0
Unrealized Gain (Loss) on Hedges		41,200			92,858			(25,149	)		(480,853	)		(480,853	)		0			0
Well Service Charges and Other Fees		0			0			0			0			0			0			0
TOTAL OPERATING REVENUE	$	1,717,366		$	1,494,567		$	146,300		$	248,009		$	386,414		$	69,286		$	12,810
OPERATING EXPENSES
Operating Expenses		1,469,908			1,440,744			0			194,560			187,872			26,496			1,774
General and Administrative Expense (Income)		(273,353	)		362,558			22,609			184,812			38,167			24,325			203
Accretion Expense on Asset Retirement Obligation		22,400			20,729			0			5,770			3,312			140			0
Impairment Charge on Oil and Gas Properties		0			0			0			0			0			0			0
Depreciation, Depletion, and Amortization		248,370			170,453			27,697			272,750			190,904			18,560			7,875
TOTAL OPERATING EXPENSES		1,467,325			1,994,484			50,306			657,892			420,255			69,521			9,852
INCOME (LOSS) FROM OPERATIONS		250,041			(499,917	)		95,994			(409,883	)		(33,841	)		(235	)		2,958
OTHER INCOME (EXPENSE)
Interest Income		7,500			0			0			0			0			0			0
Interest Expense		(104,264	)		(280,475	)		0			(146,169	)		(206,412	)		0			0
Gain (Loss) on Sale of Oil and Gas Properties		3,500			0			0			0			0			0			0
Other Income (Expense)		(5,692	)		105			0			(10,000	)		0			15,328			0
TOTAL OTHER INCOME (EXPENSE)		(98,956	)		(280,370	)		0			(156,169	)		(206,412	)		15,328			0
NET INCOME (LOSS) BEFORE MINORITY INTEREST		151,085			(780,287	)		95,994			(566,052	)		(240,253	)		15,093			2,958
MINORITY INTEREST SHARE OF INCOME (LOSS)		0			0			91,041			(488,503	)		(207,338	)		14,713			2,299
NET INCOME (LOSS)	$	151,085		$	(780,287	)	$	4,953		$	(77,549	)	$	(32,915	)	$	380		$	659

F-48

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(unaudited)

CONSOLIDATING STATEMENT OF OPERATIONS

Three Months Ended March 31, 2007

	Rex Energy II, LP			Rex Energy II Alpha, LP			Rex Energy III, LLC			Rex Energy IV, LLC			New Albany— Indiana, LLC			Rex Energy Operating Corp.			Eliminations			Total
OPERATING REVENUE
Oil and Natural Gas Sales	$	1,716,359		$	75,845		$	1,689,061		$	3,725,791		$	0		$	0		$	0		$	12,774,851
Other Operating Revenue		82,739			2,338			0			0			0			0			0			100,221
Realized Gain (Loss) on Hedges		90,472			0			466,156			363,600			0			0			0			264,838
Unrealized Gain (Loss) on Hedges		(545,901	)		(9,447	)		(624,416	)		(1,404,284	)		0			0			0			(3,436,845	)
Well Service Charges and Other Fees		0			0			0			0			0			0			0			0
TOTAL OPERATING REVENUE	$	1,343,669		$	68,736		$	1,530,801		$	2,685,107		$	0		$	0		$	0		$	9,703,065
OPERATING EXPENSES
Operating Expenses		644,446			28,988			557,322			2,823,297			0			0			(1,270,310	)		6,105,097
General and Administrative Expense (Income)		165,900			14,324			61,457			124,730			87,772			2,127,964			(959,473	)		1,981,995
Accretion Expense on Asset Retirement Obligation		15,365			812			16,306			39,376			0			0			0			124,210
Impairment Charge on Oil and Gas Properties		585,042			0			0			0			0			0			0			585,042
Depreciation, Depletion, and Amortization		711,453			29,389			853,121			1,340,950			0			77,527			0			3,949,049
TOTAL OPERATING EXPENSES		2,122,206			73,513			1,488,206			4,328,353			87,772			2,205,491			(2,229,783	)		12,745,393
INCOME (LOSS) FROM OPERATIONS		(778,537	)		(4,777	)		42,595			(1,643,246	)		(87,772	)		(2,205,491	)		2,229,783			(3,042,328	)
OTHER INCOME (EXPENSE)
Interest Income		0			0			0			1,417			0			0			0			8,917
Interest Expense		(92,878	)		0			(455,816	)		(789,799	)		0			(9,007	)		0			(2,084,820	)
Gain (Loss) on Sale of Oil and Gas Properties		167,292			5,690			0			0			0			0			0			176,482
Other Income (Expense)		(24,047	)		0			(19,200	)		0			0			2,229,783			(2,229,783	)		(43,506	)
TOTAL OTHER INCOME (EXPENSE)		50,367			5,690			(475,016	)		(788,382	)		0			2,220,776			(2,229,783	)		(1,942,927	)
NET INCOME (LOSS) BEFORE MINORITY INTEREST		(728,170	)		913			(432,421	)		(2,431,628	)		(87,772	)		15,285			0			(4,985,255	)
MINORITY INTEREST SHARE OF INCOME (LOSS)		(647,343	)		913			(231,345	)		(1,215,814	)		(52,628	)		6,114			0			(2,727,892	)
NET INCOME (LOSS)	$	(80,827	)	$	0		$	(201,076	)	$	(1,215,814	)	$	(35,144	)	$	9,171		$	0		$	(2,257,363	)

F-49

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(unaudited)

CONSOLIDATING STATEMENT OF OPERATIONS

Three Months Ended March 31, 2006

	PennTex Resources Illinois, Inc.			PennTex Resources, LP			Rex Energy Royalties, LP		Douglas Oil & Gas, LP			Douglas Westmoreland, LP			Midland Exploration, LP
OPERATING REVENUE
Oil and Natural Gas Sales	$	2,482,257		$	2,368,803		$	244,065	$	1,014,219		$	958,116		$	109,403
Other Operating Revenue		0			0			0		175,190			0			0
Realized Gain (Loss) on Hedges		(459,720	)		(877,856	)		0		(66,665	)		46,260			0
Unrealized Gain (Loss) on Hedges		(392,793	)		396,849			0		281,457			262,281			0
TOTAL OPERATING REVENUE	$	1,629,744		$	1,887,796		$	244,065	$	1,404,201		$	1,266,657		$	109,403
OPERATING EXPENSES
Operating Expenses		1,081,175			1,054,590			0		254,897			225,392			39,912
General and Administrative Expense (Income)		(214,638	)		75,356			30,331		248,241			33,487			17,731
Accretion Expense on Asset Retirement Obligation		20,712			20,712			0		6,089			4,106			0
Impairment Charge on Oil and Gas Properties		0			0			0		0			0			0
Depreciation, Depletion, and Amortization		271,015			133,602			24,301		316,923			323,219			67,346
TOTAL OPERATING EXPENSES		1,158,264			1,284,260			54,632		826,150			586,204			124,989
INCOME (LOSS) FROM OPERATIONS		471,480			603,536			189,433		578,051			680,453			(15,586	)
OTHER INCOME (EXPENSE)
Interest Income		0			0			0		4,589			0			0
Interest Expense		0			(259,233	)		0		(102,799	)		(381,145	)		0
Gain (Loss) on Sale of Oil and Gas Properties		0			0			0		0			0			0
Other Income (Expense)		5,430			(60,725	)		0		13,063			0			0
TOTAL OTHER INCOME (EXPENSE)		5,430			(319,958	)		0		(85,147	)		(381,145	)		0
NET INCOME (LOSS) BEFORE MINORITY INTEREST		476,910			283,578			189,433		492,904			299,308			(15,586	)
MINORITY INTEREST SHARE OF INCOME (LOSS)		0			0			179,658		425,376			258,303			(15,193	)
NET INCOME (LOSS)	$	476,910		$	283,578		$	9,775	$	67,528		$	41,005		$	(393	)

F-50

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(unaudited)

CONSOLIDATING STATEMENT OF OPERATIONS

Three Months Ended March 31, 2006

	Rex Energy, LP		Rex Energy II, LP			Rex Energy II Alpha, LP		New Albany— Indiana, LLC			Rex Energy Operating Corp.			Eliminations			Total
OPERATING REVENUE
Oil and Natural Gas Sales	$	33,713	$	1,876,405		$	81,810	$	0		$	0		$	0		$	9,168,791
Other Operating Revenue		0		91,196			2,754		0			0			(141,997	)		127,143
Realized Gain (Loss) on Hedges		0		(31,876	)		0		0			0			0			(1,389,857	)
Unrealized Gain (Loss) on Hedges		0		(428,255	)		0		0			0			0			119,539
TOTAL OPERATING REVENUE	$	33,713	$	1,507,470		$	84,564	$	0		$	0		$	(141,997	)	$	8,025,616
OPERATING EXPENSES
Operating Expenses		822		437,333			22,258		0			0			(672,540	)		2,443,839
General and Administrative Expense (Income)		0		141,064			5,371		10,793			1,738,857			(1,242,886	)		843,707
Accretion Expense on Asset Retirement Obligation		0		45,017			1,144		0			0			0			97,780
Impairment Charge on Oil and Gas Properties		0		0			0		0			0			0			0
Depreciation, Depletion, and Amortization		1,494		787,002			38,924		0			3,525			0			1,967,351
TOTAL OPERATING EXPENSES		2,316		1,410,416			67,697		10,793			1,742,382			(2,057,423	)		5,352,677
INCOME (LOSS) FROM OPERATIONS		31,397		97,054			16,867		(10,793	)		(1,742,382	)		1,773,429			2,672,939
OTHER INCOME (EXPENSE)
Interest Income		0		10,149			0		21,230			0			0			35,968
Interest Expense		0		(23,152	)		0		0			0			0			(766,329	)
Gain (Loss) on Sale of Oil and Gas Properties		0		0			0		0			0			0			0
Other Income (Expense)		0		(70,865	)		0		0			1,773,429			(1,773,429	)		(113,097	)
TOTAL OTHER INCOME (EXPENSE)		0		(83,868	)		0		21,230			1,773,429			(1,773,429	)		(843,458	)
NET INCOME (LOSS) BEFORE MINORITY INTEREST		31,397		13,186			16,867		10,437			31,047			0			1,829,481
MINORITY INTEREST SHARE OF INCOME (LOSS)		24,402		11,722			16,867		7,510			12,419			0			921,064
NET INCOME (LOSS)	$	6,995	$	1,464		$	0	$	2,927		$	18,628		$	0		$	908,417

F-51

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(unaudited)

CONSOLIDATING STATEMENT OF CASH FLOWS

Three Months Ended March 31, 2007

	PennTex Resources Illinois, Inc.			PennTex Resources, LP			Rex Energy Royalties, LP			Douglas Oil & Gas, LP			Douglas Westmoreland, LP			Midland Exploration, LP			Rex Energy, LP
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	151,085		$	(780,287	)	$	4,953		$	(77,549	)	$	(32,915	)	$	380		$	659
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Minority Interest Share of Income (Loss)		0			0			91,041			(488,503	)		(207,338	)		14,713			2,299
Depreciation, Depletion, and Amortization		248,370			170,453			27,697			272,750			190,904			18,560			7,875
Unrealized (Gain) Loss on Hedges		(41,200	)		(92,858	)		25,149			480,853			480,853			0			0
Impairment of Oil and Gas Properties		0			0			0			0			0			0			0
Accretion Expense on Asset Retirement Obligation		22,400			20,729			0			5,770			3,312			140			0
Plugging Costs Incurred		(30,366	)		0			0			0			0			0			0
(Gain) Loss on Sale of Oil and Gas Properties		(3,500	)		0			0			0			0			0			0
Cash Flows from Operating Activities Due to
(Increase) in Accounts Receivable		(288,570	)		80,108			(61,879	)		362,963			(89,879	)		29,552			(61,081	)
(Increase) Decrease in Inventory, Prepaid Expenses and Other Assets		(565,494	)		4,272			0			(33,579	)		(6,027	)		1,552			0
Increase (Decrease) in Accounts Payable and Accrued Expenses		151,080			14,666			19,188			(96,988	)		(201,316	)		(25,919	)		(726	)
Net Changes in Other Assets and Liabilities		(420,803	)		1,130,616			0			(141,876	)		(97,524	)		15,745			218,902
NET CASH PROVIDED BY OPERATING ACTIVITIES		(776,998	)		547,699			106,149			283,841			40,070			54,723			167,928
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Oil and Gas Properties, Prospects and Other Assets		3,500			0			0			0			0			0			0
Acquisitions of Oil & Gas Properties		0			0			0			0			0			0			0
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(603,738	)		(575,504	)		0			(79,773	)		(38,854	)		(159	)		0
NET CASH USED IN INVESTING ACTIVITIES		(600,238	)		(575,504	)		0			(79,773	)		(38,854	)		(159	)		0
CASH FLOWS FROM FINANCING ACTIVITIES
Net Proceeds from (Repayments of) Long-Term Debts and Lines of Credit		2,377,941			0			0			49,601			0			0			0
Net Proceeds from (Repayments of) Loans and Other Notes Payable		0			0			0			(4,766	)		(1,216	)		0			0
Net Proceeds from (Repayments to) Related Parties		(1,000,000	)		0			0			0			0			0			0
Financing Costs Paid		0			0			0			0			0			0			0
Deferred Offering Costs Paid		0			0			0			0			0			0			0
Capital Contributions		0			0			0			0			0			0			0
Cash Distributions		0			0			(107,631	)		(248,903	)		0			(102,465	)		(218,902	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		1,377,941			0			(107,631	)		(204,068	)		(1,216	)		(102,465	)		(218,902	)
NET (DECREASE) INCREASE IN CASH		705			(27,805	)		(1,482	)		0			0			(47,901	)		(50,974	)
CASH—BEGINNING		6,951			27,805			1,482			0			0			64,245			71,467
CASH—ENDING		7,656			0			0			0			0			16,344			20,493
SUPPLEMENTAL DISCLOSURES
Interest Paid		104,264			280,475			0			146,169			206,412			0			0
Non-Cash Activities
Redemption—Baseline Property Distribution		0			0			0			0			0			0			0
Conversion of Lance T. Shaner Loan Payable to Capital		0			820,000			0			0			0			0			0

F-52

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(unaudited)

CONSOLIDATING STATEMENT OF CASH FLOWS

Three Months Ended March 31, 2007

	Rex Energy II, LP			Rex Energy II Alpha, LP			Rex Energy III, LLC			Rex Energy IV, LLC			New Albany- Indiana, LLC			Rex Energy Operating Corp.			Eliminations		Total
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(80,827	)	$	0		$	(201,076	)	$	(1,215,813	)	$	(35,144	)	$	9,171		0		(2,257,363	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Minority Interest Share of Income (Loss)		(647,343	)		913			(231,345	)		(1,215,814	)		(52,628	)		6,113		0		(2,727,892	)
Depreciation, Depletion, and Amortization		711,453			29,389			853,121			1,340,950			0			77,527		0		3,949,049
Unrealized (Gain) Loss on Hedges		545,901			9,447			624,416			1,404,284			0			0		0		3,436,845
Impairment of Oil and Gas Properties		585,042			0			0			0			0			0		0		585,042
Accretion Expense on Asset Retirement Obligation		15,365			812			16,306			39,376			0			0		0		124,210
Plugging Costs Incurred		0			0			0			0			0			0		0		(30,366	)
(Gain) Loss on Sale of Oil and Gas Properties		(167,292	)		(5,690	)		0			0			0			0		0		(176,482	)
Cash Flows from Operating Activities Due to
(Increase) in Accounts Receivable		(1,494,178	)		15,587			(44,561	)		204,559			(2,414,363	)		46,391		3,541,578		(173,773	)
(Increase) Decrease in Inventory, Prepaid Expenses and Other Assets		(26,512	)		(424	)		41,240			10,260			0			510,534		0		(64,178	)
Increase (Decrease) in Accounts Payable and Accrued Expenses		(247,246	)		0			(559,103	)		(1,904	)		428,140			475,839		0		(44,289	)
Net Changes in Other Assets and Liabilities		(892,246	)		(1,944	)		14,055			(687	)		(98,631	)		(461,514	)	385,840		(350,067	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		(1,697,883	)		48,090			513,053			565,211			(2,172,626	)		664,061		3,927,418		2,270,736
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Oil and Gas Properties, Prospects and Other Assets		213,400			6,600			0			0			0			0		0		223,500
Acquisitions of Oil & Gas Properties		(1,080,000	)		0			0			0			0			0		0		(1,080,000	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(565,684	)		(2,968	)		(462,296	)		(1,149,946	)		(1,338,086	)		(142,462	)	0		(4,959,470	)
NET CASH USED IN INVESTING ACTIVITIES		(1,432,284	)		3,632			(462,296	)		(1,149,946	)		(1,338,086	)		(142,462	)	0		(5,815,970	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Proceeds from (Repayments of) Long-Term Debts and Lines of Credit		3,891,878			0			0			1,050,000			0			(275,518	)	0		7,093,902
Net Proceeds from (Repayments of) Loans and Other Notes Payable		0			0			0			0			0			297,109		0		291,127
Net Proceeds from (Repayments to) Related Parties		0			0			0			0			0			0		0		(1,000,000	)
Financing Costs Paid		(215,678	)		0			0			(300,000	)		0			0		0		(515,678	)
Deferred Offering Costs Paid		0			0			0			0			0			(569,680	)	0		(569,680	)
Capital Contributions		0			0			0			0			4,461,545			0		(4,161,545	)	300,000
Cash Distributions		(569,196	)		(50,000	)		0			0			0			0		234,127		(1,062,970	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		3,107,004			(50,000	)		0			750,000			4,461,545			(548,089	)	(3,927,418	)	4,536,701
NET (DECREASE) INCREASE IN CASH		(23,163	)		1,722			50,757			165,265			950,833			(26,490	)	0		991,467
CASH—BEGINNING		57,164			2,606			0			239,683			101,903			26,490		0		599,796
CASH—ENDING		34,001			4,328			50,757			404,948			1,052,736			0		0		1,591,263
SUPPLEMENTAL DISCLOSURES
Interest Paid		92,878			0			455,816			789,799			0			9,007		0		2,084,820
Non-Cash Activities
Redemption—Baseline Property Distribution		0			0			0			0			7,970,357			0		0		7,970,357
Conversion of Lance T. Shaner Loan Payable to Capital		0			0			0			0			0			0		0		820,000

F-53

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(unaudited)

CONSOLIDATING STATEMENT OF CASH FLOWS

Three Months Ended March 31, 2006

	PennTex Resources Illinois, Inc.			PennTex Resources, LP			Rex Energy Royalties, LP			Douglas Oil & Gas, LP			Douglas Westmoreland, LP			Midland Exploration, LP
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	476,910		$	283,578		$	9,775		$	67,528		$	41,005		$	(393	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Minority Interest Share of Income (Loss)		0			0			179,658			425,376			258,303			(15,193	)
Depreciation, Depletion, and Amortization		271,015			133,602			24,301			316,923			323,219			67,346
Unrealized (Gain) Loss on Hedges		392,793			(396,849	)		0			(281,457	)		(262,281	)		0
Impairment of Oil and Gas Properties		0			0			0			0			0			0
Accretion Expense on Asset Retirement Obligation		20,712			20,712			0			6,089			4,106			0
Plugging Costs Incurred		0			0			0			0			0			0
(Gain) Loss on Sale of Oil and Gas Properties		0			0			0			0			0			0
Cash Flows from Operating Activities Due to		0			0			0			0			0			0
(Increase) in Accounts Receivable		(880,291	)		(89,853	)		363,438			(1,544,594	)		(468,159	)		74,319
(Increase) Decrease in Inventory, Prepaid Expenses and Other Assets		59,173			418,040			0			(86,477	)		2,468			(3,502	)
Increase (Decrease) in Accounts Payable and Accrued Expenses		15,307			35,216			(2,955	)		(490,276	)		(43,711	)		77,091
Net Changes in Other Assets and Liabilities		(20,557	)		(20,557	)		0			103			0			0
NET CASH PROVIDED BY OPERATING ACTIVITIES		335,062			383,889			574,217			(1,586,785	)		(145,050	)		199,668
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Oil and Gas Properties, Prospects and Other Assets		0			0			0			0			0			0
Acquisitions of Oil & Gas Properties		0			0			0			(7,454	)		0			(298	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(289,088	)		(270,864	)		0			(26,830	)		(15,894	)		(5,687	)
NET CASH USED IN INVESTING ACTIVITIES		(289,088	)		(270,864	)		0			(34,284	)		(15,894	)		(5,985	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Proceeds from (Repayments of) Long-Term Debts and Lines of Credit		3,016,546			10,089,406			0			1,568,831			(3,422	)		0
Net Proceeds from (Repayments of) Loans and Other Notes Payable		69,152			0			0			21,348			1,761			0
Net Proceeds from (Repayments to) Related Parties		0			(8,136,423	)		0			0			0			0
Financing Costs Paid		0			(344,478	)		0			(238,774	)		0			0
Deferred Offering Costs Paid		0			0			0			0			0			0
Capital Contributions		0			700,000			0			0			0			0
Cash Distributions		(3,100,000	)		(1,863,577	)		(322,099	)		(216,473	)		0			(99,079	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		(14,302	)		444,928			(322,099	)		1,134,932			(1,661	)		(99,079	)
NET (DECREASE) INCREASE IN CASH		31,672			557,953			252,118			(486,137	)		(162,605	)		94,604
CASH—BEGINNING		0			0			711			606,373			210,242			18,778
CASH—ENDING	$	31,671		$	557,953		$	252,829		$	120,236		$	47,639		$	113,382
SUPPLEMENTAL DISCLOSURES
Interest Paid		0			259,233			0			102,799			381,145			0
Non-Cash Activities
Repayment of Lance T. Shaner via Transfer of New Albany Interests		0			0			0			0			0			0
Accrued Distribution		0			0			0			0			0		$	28,900
Conversion of Deposit on Leasehold Acreage to Leasehold Acquisition		0			0			0			0			0			0

F-54

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

(unaudited)

CONSOLIDATING STATEMENT OF CASH FLOWS

Three Months Ended March 31, 2006

	Rex Energy, LP			Rex Energy II, LP			Rex Energy II Alpha, LP			New Albany— Indiana, LLC			Rex Energy Operating Corp.			Eliminations			Total
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	6,995		$	1,464		$	0		$	2,927		$	18,628		$	0		$	908,417
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Minority Interest Share of Income (Loss)		24,402			11,722			16,867			7,510			12,419			0			921,064
Depreciation, Depletion, and Amortization		1,494			787,002			38,924			0			3,525			0			1,967,351
Unrealized (Gain) Loss on Hedges		0			428,255			0			0			0			0			(119,539	)
Impairment of Oil and Gas Properties		0			0			0			0			0			0			0
Accretion Expense on Asset Retirement Obligation		0			45,017			1,144			0			0			0			97,780
Plugging Costs Incurred		0			0			0			0			0			0			0
(Gain) Loss on Sale of Oil and Gas Properties		0			0			0			0			0			0			0
Cash Flows from Operating Activities Due to		0			0			0			0			0			0			0
(Increase) in Accounts Receivable		(20,856	)		(1,629,467	)		37,082			4,992			6,735			2,510,158			(1,636,496	)
(Increase) Decrease in Inventory, Prepaid Expenses and Other Assets		(11,301	)		(3,826	)		20			0			(132,507	)		0			242,088
Increase (Decrease) in Accounts Payable and Accrued Expenses		0			(487,166	)		(22,447	)		510			62,181			0			(856,250	)
Net Changes in Other Assets and Liabilities		0			0			0			0			0			0			(41,011	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		734			(846,999	)		71,590			15,939			(29,019	)		2,510,158			1,483,404
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Oil and Gas Properties, Prospects and Other Assets		0			0			0			0			0			0			0
Acquisitions of Oil & Gas Properties		0			(10,198,884	)		(310,000	)		(7,788,619	)		0			0			(18,305,255	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(20,068	)		(580,738	)		(33,077	)		0			(41,692	)		0			(1,283,938	)
NET CASH USED IN INVESTING ACTIVITIES		(20,068	)		(10,779,622	)		(343,077	)		(7,788,619	)		(41,692	)		0			(19,589,193	)
CASH FLOWS FROM FINANCING ACTIVITIES																	0
Net Proceeds from (Repayments of) Long-Term Debts and Lines of Credit		0			1,876,111			0			0			(4,641	)		0			16,542,831
Net Proceeds from (Repayments of) Loans and Other Notes Payable		0			0			0			0			37,539			0			129,800
Net Proceeds from (Repayments to) Related Parties		0			0			0			0			0			0			(8,136,423	)
Financing Costs Paid		0			0			0			0			0			0			(583,252	)
Deferred Offering Costs Paid		0			0			0			0			0			0			0
Capital Contributions		0			8,721,000			310,000			7,807,168			0			(2,510,158	)		15,028,010
Cash Distributions		0			(600,942	)		(30,609	)		0			0			0			(6,232,779	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		0			9,996,169			279,391			7,807,168			32,898			(2,510,158	)		16,748,187
NET (DECREASE) INCREASE IN CASH		(19,334	)		(1,630,452	)		7,904			34,488			(37,813	)		0			(1,357,602	)
CASH—BEGINNING		54,692			1,630,452			6,005			0			160,297			0			2,687,550
CASH—ENDING	$	35,358		$	0		$	13,909		$	34,488		$	122,483			0		$	1,329,948
SUPPLEMENTAL DISCLOSURES
Interest Paid		0			23,152			0			0			0			0			766,329
Non-Cash Activities
Repayment of Lance T. Shaner via Transfer of New Albany Interests		0			0			0		$	1,715,000			0			0		$	1,715,000
Accrued Distribution		0			0			0			0			0			0		$	28,900
Conversion of Deposit on Leasehold Acreage to Leasehold Acquisition		0			0			0		$	3,500,000			0			0		$	3,500,000

F-55

REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS

CONSOLIDATING ASSET RETIREMENT OBLIGATION

March 31, 2007

	PennTex Resources Illinois, Inc.		PennTex Resources, LP		Rex Energy Royalties, LP	Douglas Oil & Gas, LP	Douglas Westmoreland, LP	Midland Exploration, LP	Rex Energy, LP	Rex Energy II, LP	Rex Energy II Alpha, LP	Rex Energy III, LLC	Rex Energy IV, LLC		New Albany- Indiana, LLC		Rex Energy Operating Corp.	Total
Total Asset Retirement Obligation—December 31, 2005	854,041		854,042		—	206,381	116,538	7,613	—	288,206	31,337	—	—		—		—	2,358,158
Initial Asset Retirement Obligation Capitalized	203		195		—	2,416	3,903	—	—	401,316	3,189	593,027	1,485,122		16,877		—	2,506,248
Pluggin Costs Incurred and Adjustments	(16,357	)	(45,640	)	—	—	—	—	—	—	—	—	(9,428	)	—		—	(71,425	)
Asset Retirement Obligation Accretion Expense	82,681		78,972		—	20,880	12,044	762	—	73,371	3,605	59,304	143,882		—		—	475,501
Total Asset Retirement Obligation—December 31, 2006	920,568		887,569		—	229,677	132,485	8,375	—	762,893	38,131	652,331	1,619,576		16,877		—	5,268,482
Initial Asset Retirement Obligation Capitalized	100		96		—	1,138	—	—	—	277,893	—	781	189		—		—	280,197
Pluggin Costs Incurred and Adjustments	—		—		—	—	—	—	—	—	—	—	—		(6,610	)	—	(6,610	)
Asset Retirement Obligation Accretion Expense	22,400		20,729		—	5,770	3,312	140	—	15,365	812	16,306	39,376		—		—	124,210
Total Asset Retirement Obligation—March 31, 2007	943,068		908,394		—	236,585	135,797	8,515	—	1,056,151	38,943	669,418	1,659,141		10,267		—	5,666,279

F-56

Annual Financial Statements of the

Founding Companies of Rex Energy Corporation

F-57

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Rex Energy Corporation

State College, Pennsylvania

We have audited the accompanying combined balance sheets of Douglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, New Albany-Indiana LLC, PennTex Resources L.P., PennTex Resources Illinois Inc., Rex Energy Limited Partnership, Rex Energy II Limited Partnership, Rex Energy III LLC, Rex Energy IV LLC, Rex Energy II Alpha Limited Partnership, Rex Energy Operating Corp. and Rex Energy Royalties Limited Partnership (the “Founding Companies of Rex Energy Corporation”) as of December 31, 2006 and 2005 and the related combined statements of operations, owners’ equity (deficit) and minority interests, and cash flows for each of the three years in the period ended December 31, 2006. These combined financial statements are the responsibility of Rex Energy Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we do not express such an opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of the Founding Companies of Rex Energy Corporation as of December 31, 2006 and 2005, and the combined results of operations, owners’ equity (deficit) and minority interest, and cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

Malin, Bergquist & Company, LLP

Pittsburgh, Pennsylvania

April 20, 2007

F-58

FOUNDING COMPANIES OF REX ENERGY CORPORATION

COMBINED BALANCE SHEETS

	December 31,
	2006			2005
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	599,796		$	2,687,550
Restricted Cash		0			500,000
Accounts Receivable		6,885,933			5,349,373
Short-Term Derivative Instruments		1,274,865			0
Inventory, Prepaid Expenses and Other		1,520,252			785,731
TOTAL CURRENT ASSETS		10,280,846			9,322,654
PROPERTY AND EQUIPMENT (SUCCESSFUL EFFORTS METHOD)
Evaluated Oil and Gas Properties		127,370,445			45,030,383
Unevaluated Oil and Gas Properties		14,569,281			1,261,167
Other Property and Equipment		4,181,843			1,375,322
Wells in Progress		2,844,481			643,118
Pipelines		1,764,439			1,622,708
TOTAL PROPERTY AND EQUIPMENT		150,730,489			49,932,698
Less: Accumulated Depreciation, Depletion and Amortization		(17,714,633	)		(7,667,842	)
NET PROPERTY AND EQUIPMENT		133,015,856			42,264,856
OTHER ASSETS
Other Assets—Net		1,171,795			3,703,104
Long-Term Derivative Instruments		142,855			0
TOTAL OTHER ASSETS		1,314,650			3,703,104
TOTAL ASSETS	$	144,611,352		$	55,290,614
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts Payable and Accrued Expenses	$	8,335,580		$	7,724,766
Short-Term Derivative Instruments		2,977,697			5,135,667
Accrued Distributions		102,465			3,621,991
Lines of Credit		37,580,634			5,841,771
Current Portion of Long-Term Debt		2,867,540			121,517
Related Party Payable		1,820,000			9,851,522
TOTAL CURRENT LIABILITIES		53,683,916			32,297,234
LONG-TERM LIABILITIES
Long-Term Debt		44,961,271			3,000,000
Other Loans and Notes Payable—Long-Term Portion		481,373			360,047
Long-Term Derivative Instruments		1,698,125			3,165,655
Participation Liability—Net		2,141,109			574,254
Other Liabilities		405,080			325,036
Asset Retirement Obligation		5,268,482			2,358,158
TOTAL LONG-TERM LIABILITIES		54,955,440			9,783,150
TOTAL LIABILITIES		108,639,356			42,080,384
COMMITMENTS AND CONTINGENCIES (NOTE 5)
MINORITY INTERESTS		36,589,360			24,129,968
OWNERS’ EQUITY
Common Stock		1,060			1,060
Additional Paid-In Capital		1,460,000			1,460,000
Accumulated Stockholders’ (Deficit)		(580,578	)		(3,741,753	)
Partners’ and Members’ (Deficit)		(1,497,846	)		(8,639,045	)
TOTAL OWNERS’ DEFICIT		(617,364	)		(10,919,738	)
TOTAL LIABILITIES, MINORITY INTERESTS AND OWNERS’ DEFICIT	$	144,611,352		$	55,290,614

SEE ACCOMPANYING NOTES.

F-59

FOUNDING COMPANIES OF REX ENERGY CORPORATION

COMBINED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2006			2005			2004
OPERATING REVENUE
Oil and Natural Gas Sales	$	43,596,017		$	29,517,590		$	14,158,912
Other Operating Revenue		469,582			270,140			697,412
Realized Gain (Loss) on Hedges		(4,436,347	)		(7,929,478	)		(941,511	)
Unrealized Gain (Loss) on Hedges		5,043,220			(5,541,043	)		(1,395,531	)
TOTAL OPERATING REVENUE		44,672,472			16,317,209			12,519,282
OPERATING EXPENSES
Operating Expenses		14,254,594			10,852,439			6,262,259
Production Taxes		551,082			466,223			268,000
Gas Contract Purchases		428,379			402,317			177,515
General and Administrative Expense		6,212,139			3,788,932			2,228,986
Accretion Expense on Asset Retirement Obligation		475,501			199,758			122,008
Impairment Charge on Oil and Gas Properties		0			107,119			3,024,267
Depreciation, Depletion, and Amortization		10,746,805			3,120,242			1,917,257
TOTAL OPERATING EXPENSES		32,668,500			18,937,030			14,000,292
INCOME (LOSS) FROM OPERATIONS		12,003,972			(2,619,821	)		(1,481,010	)
OTHER INCOME (EXPENSE)
Interest Income		93,684			444,438			18,631
Interest Expense		(6,110,023	)		(1,697,461	)		(867,386	)
Gain (Loss) on Sale of Oil and Gas Properties		91,416			1,016,545			659,364
Other Income (Expense)		(131,713	)		215,678			(21,171	)
TOTAL OTHER INCOME (EXPENSE)		(6,056,636	)		(20,800	)		(210,562	)
NET INCOME (LOSS) BEFORE MINORITY INTEREST		5,947,336			(2,640,621	)		(1,691,572	)
MINORITY INTEREST SHARE OF INCOME (LOSS)		2,133,655			2,303,982			(2,061,623	)
NET INCOME (LOSS)	$	3,813,681		$	(4,944,603	)	$	370,051

SEE ACCOMPANYING NOTES.

F-60

FOUNDING COMPANIES OF REX ENERGY CORPORATION

COMBINED STATEMENTS OF OWNERS’ EQUITY (DEFICIT) AND MINORITY INTERESTS

YEARS ENDED DECEMBER 31, 2006, 2005, AND 2004

	Common Stock		Additional Paid In Capital		Stockholders’ Equity			Members’ Equity			Partners’ Equity			Total Owners’ Equity			Minority Interests
BALANCE—January 1, 2004	$	0	$	0	$	0		$	0		$	2,621,631		$	2,621,631		$	10,294,909
CAPITAL CONTRIBUTIONS												724,202			724,202			4,749,590
DISTRIBUTIONS												(517,605	)		(517,605	)		(1,286,642	)
NET INCOME (LOSS)												370,051			370,051			(2,061,623	)
BALANCE—December 31, 2004	$	0	$	0	$	0		$	0		$	3,198,279		$	3,198,279		$	11,696,234
CAPITAL CONTRIBUTIONS		1,060		1,460,000		4,502,282			21,000			1,260,320			7,244,662			13,383,801
DISTRIBUTIONS						(3,919,264	)					(1,744,548	)		(5,663,812	)		(2,582,845	)
PARTNERSHIP REDEMPTION												(10,754,264	)		(10,754,264	)		(671,204	)
NET INCOME (LOSS)						(4,324,771	)					(619,832	)		(4,944,603	)		2,303,982
BALANCE—December 31, 2005	$	1,060	$	1,460,000	$	(3,741,753	)	$	21,000		$	(8,660,045	)	$	(10,919,738	)	$	24,129,968
CAPITAL CONTRIBUTIONS									6,973,958			1,886,638			8,860,596			14,098,717
DISTRIBUTIONS						(55,000	)					(2,316,903	)		(2,371,903	)		(3,772,980	)
NET INCOME (LOSS)						3,216,175			(1,025,716	)		1,623,222			3,813,681			2,133,655
BALANCE—December 31, 2006	$	1,060	$	1,460,000	$	(580,578	)	$	5,969,242		$	(7,467,088	)	$	(617,364	)	$	36,589,360

SEE ACCOMPANYING NOTES.

F-61

FOUNDING COMPANIES OF REX ENERGY CORPORATION

COMBINED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	3,813,681		$	(4,944,603	)	$	370,051
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Minority Interest Share of Income (Loss)		2,133,655			2,303,982			(2,061,623	)
Depreciation, Depletion, and Amortization		10,746,805			3,120,242			1,917,257
Bad Debt Expense		75,985			6,053			0
Unrealized (Gain) Loss on Hedges		(5,043,220	)		5,541,043			1,395,531
Impairment of Oil and Gas Properties		0			107,119			3,024,267
Accretion Expense on Asset Retirement Obligation		475,501			199,758			122,008
Amortization of Participation Liability		1,566,855			443,634			130,620
(Gain) Loss on Sale of Oil and Gas Properties		(91,416	)		(1,016,545	)		(659,364	)
Cash Flows from Operating Activities Due to
(Increase) in Accounts Receivable		(1,536,560	)		(1,418,287	)		(2,390,551	)
(Increase) Decrease in Inventory, Prepaid Expenses and Other Assets		(734,521	)		891,586			685,533
Increase (Decrease) in Accounts Payable and Accrued Expenses		610,814			4,402,238			2,702,768
(Increase) Decrease in Other Assets and Liabilities		286,285			(109,943	)		746,750
NET CASH PROVIDED BY OPERATING ACTIVITIES		12,303,864			9,526,277			5,983,247
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Oil and Gas Properties, Prospects and Other Assets		157,066			3,291,258			1,176,945
Deposits on Leasehold Acreage		(34,600	)		(3,420,224	)		(100,000	)
Acquisitions of Undeveloped Acreage		(10,604,956	)		(246,203	)		0
Acquisitions of Oil and Gas Properties and Related Equipment		(67,796,366	)		(14,904,621	)		(6,677,871	)
Acquisitions of Other Property and Equipment		(1,313,770	)		(76,790	)		0
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(13,182,784	)		(4,047,556	)		(4,010,756	)
Capital Expenditures for Property & Equipment		(1,054,564	)		0			0
NET CASH USED IN INVESTING ACTIVITIES		(93,829,974	)		(19,404,136	)		(9,611,682	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debts and Lines of Credit		86,702,988			470,069			12,349,495
Repayments of Long-Term Debts and Lines of Credit		(10,512,907	)		(3,566,319	)		(7,246,580	)
Proceeds from Loans and Other Notes Payable		762,228			1,430,543			0
Repayments of Loans and Other Notes Payable		(351,405	)		(1,450,974	)		0
Net Proceeds from (Repayments to) Related Parties		(6,316,423	)		9,851,423			0
Payments of Financing Costs		(1,701,007	)		0			(170,128	)
Capital Contributions		18,383,614			16,315,181			3,150,000
Cash Distributions and Redemptions		(7,528,732	)		(13,277,972	)		(2,625,487	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		79,438,356			9,771,951			5,457,300
NET (DECREASE) INCREASE IN CASH		(2,087,754	)		(105,908	)		1,828,865
CASH—BEGINNING		2,687,550			2,793,458			964,593
CASH—ENDING	$	599,796		$	2,687,550		$	2,793,458
SUPPLEMENTAL DISCLOSURES
Interest Paid	$	6,543,881		$	1,235,824		$	685,896
Non-Cash Activities
Accrued Distributions	$	102,468		$	427,979		$	0
Contributions of Capital Assets at Formation by Minority Interest Holders	$	0		$	0		$	509,219
Distribution of Non-Cash to Lance T. Shaner	$	0		$	3,270,043		$	0
Redemption—Property Distribution	$	0		$	3,758,926		$	0
Loan Costs Paid by Line of Credit Draws	$	505,516		$	0		$	0
Capital Contributions Included in Other Accounts Receivable	$	100		$	0		$	0
Repayments of Lance T. Shaner via Transfer of New Albany Interests	$	1,715,000		$	0		$	0

SEE ACCOMPANYING NOTES.

F-62

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of the Company

Rex Energy Corporation (the “Company”), a Delaware corporation, was formed in 2007 with the intent of acquiring all of the operations of the Founding Companies (as defined below), and simultaneously conducting an initial public offering of the Company’s common stock. Upon consummation of the acquisitions of the operations of the Founding Companies, the Company will be an independent oil and gas company with ownership interests in approximately 2,600 wells located in the Illinois Basin, the Appalachian Basin and the southwestern region of the United States. The Company is headquartered in State College, Pennsylvania, and will have regional offices in Canonsburg, Pennsylvania, Midland, Texas and Bridgeport, Illinois.

Principles of Combination and Reporting

The combined financial statements of the Founding Companies present historical combined financial data as of December 31, 2006 and 2005 and for the three years ended December 31, 2006, 2005, and 2004. The historical combined financial statements are derived from the historical audited financial data of the Founding Companies, all of which are under the common control of Lance T. Shaner through his direct and indirect ownership interests and other contractual arrangements, as well as under the common management of Rex Operating. All material intercompany balances and transactions have been eliminated.

It has been determined that PennTex Resources, as the earliest formed entity and by virtue of being wholly-owned by Lance T. Shaner, will be considered the accounting acquirer in the merger transactions by which the Company will acquire all of the operations of the Founding Companies. As such, the acquisition of interests in the Founding Companies not owned by Mr. Shaner will be accounted for as a purchase, and the excess of the purchase price over historical book value will be pushed down to the balance sheet of the Company. The interests in the Founding Companies not owned by Mr. Shaner are presented as minority interests in these combined financial statements.

As each of the Founding Companies was taxed as a partnership or Subchapter S corporation for each of the years indicated for federal and state income tax purposes, the combined financial statements make no provision for income taxes.

The following table defines the Founding Companies of Rex Energy Corporation, and the level of ownership represented in these combined financial statements, exclusive of minority interests.

Douglas Oil & Gas Limited Partnership	“Douglas Oil & Gas”	13.70	%
Douglas Westmoreland Limited Partnership	“Douglas Westmoreland”	13.70
Rex Energy Royalties Limited Partnership	“Rex Royalties”	5.16
Midland Exploration Limited Partnership	“Midland”	2.52
New Albany-Indiana, LLC	“New Albany”	28.04
PennTex Resources Illinois, Inc.	“PennTex Illinois”	100.00
PennTex Resources Limited Partnership	“PennTex Resources”	100.00
Rex Energy Limited Partnership	“Rex I”	22.27
Rex Energy II Limited Partnership	“Rex II”	11.10
Rex Energy II Alpha Limited Partnership	“Rex II Alpha”	0.00
Rex Energy III, LLC	“Rex III”	46.50
Rex Energy IV, LLC	“Rex IV”	50.00
Rex Operating Corp.	“Rex Operating”	60.00

F-63

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Proposed Merger and Initial Public Offering

Management of the Company has proposed a series of mergers and reorganization transactions of the Founding Companies in order to pursue an initial public offering of the Company.

The basis of presentation presented in this financial statement is contingent upon successful completion of the Company’s proposed initial public offering. Management intends to use the proceeds of the offering, net of underwriting discounts and fees and expenses of the offering and the merger transactions, to retire all senior debt facilities of the Founding Companies, totaling approximately $85 million as of December 31, 2006, with any excess proceeds to be used for working capital purposes.

Description of Founding Companies

Douglas Oil & Gas

Douglas Oil & Gas, a Delaware limited partnership, was formed in 2003 through a contribution of assets and liabilities from Douglas Oil & Gas, Inc. and Rex I. Rex Energy, LLC, which is 100% owned by Rex I, is the general partner of Douglas Oil & Gas. Douglas Oil & Gas (and its predecessor Douglas Oil & Gas, Inc.) has been an independent oil and gas producer with an emphasis on the development of natural gas reserves in the United States since 1984. Historically, Douglas Oil & Gas has been involved in natural gas exploration projects in the Appalachian Basin. At December 31, 2006, Douglas Oil & Gas had ownership interests in approximately 521 wells located in the states of Texas, New Mexico, and Pennsylvania. Additionally, Douglas Oil & Gas is a member in New Albany-Indiana, LLC. See Note 25: Subsequent Events.

Douglas Westmoreland

Douglas Westmoreland, a Delaware limited partnership, was formed in 2004. Rex I is the general partner of Douglas Westmoreland. Douglas Oil & Gas is the sole limited partner. Douglas Westmoreland engages in the exploration, acquisition, management, leasing, development, and extraction of natural gas from underground reservoirs. Douglas Westmoreland owns a 100.0% working interest in approximately 73 natural gas wells located in Westmoreland County, Pennsylvania.

Rex Royalties

Rex Royalties, a Delaware limited partnership, was formed in 2002. Douglas Oil & Gas is the general partner of Rex Royalties. Rex Royalties engages in the business of acquiring, owning, operating, managing, leasing, developing, or otherwise disposing of royalty interests in oil and natural gas properties. Rex Royalties does not engage in the acquisition of working interests in oil and gas properties, or engage in the exploration, development, production, or operational activities with respect to any oil and gas property. Rex Royalties owns royalty interests in the same 49 natural gas wells owned by Douglas Westmoreland.

Midland

Midland, a Delaware limited partnership was formed October 2004. The business of Midland is to evaluate, generate and or acquire oil and natural gas prospects or producing properties. Midland owns interests in approximately 22 wells located in the states of New Mexico and Texas. Douglas Oil & Gas serves as its general partner.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

New Albany

New Albany, a Delaware limited liability company, was formed in November 2005 for the purpose of acquiring working interests in leasehold acreage believed to contain the New Albany Shale formations in the Illinois Basin, located in southern Indiana. Rex Operating originally was a 49.0% member of New Albany, but in January 2006, Rex Operating withdrew as a member and assigned its membership interests to Lance T. Shaner, Shaner & Hulburt Capital Partners Limited Partnership, Rex II, Douglas Oil & Gas, and Rex Energy Wabash, LLC. Baseline Oil & Gas Corp. (“Baseline”) originally was a 50.0% member of New Albany. Rex Energy Wabash, LLC (wholly owned by Shaner & Hulburt Capital Partners Limited Partnership) is the managing member of New Albany. See Note 25: Subsequent Events.

PennTex Illinois

In January 2005, Lance T. Shaner acquired 100.0% of the common stock of PennTex Illinois, a Delaware corporation, formerly known as ERG Illinois, Inc., from ERG Holdings, Inc. PennTex Illinois engages in the acquisition and operation of oil wells. PennTex Illinois owns and is the operator of a 26.0% working interest in wells located in the states of Illinois and Indiana. As of December 31, 2006, PennTex Illinois owns interests in approximately 1,621 active oil producing and injection wells.

PennTex Resources

PennTex Resources, a Texas limited partnership, was formed in November 1997 by its 1.0% general partner, Penn Tex Energy, Inc. (wholly owned by Lance T. Shaner), and by Lance T. Shaner (59.0%) and Thomas J. Taylor (40.0%) as limited partners. In September 2005, the partners agreed to a redemption of Thomas J. Taylor’s limited partnership interest. In consideration for the redemption of his 40.0% limited partnership interest, Thomas J. Taylor received PennTex Resources’ interests in all wells located in the states of Texas, Oklahoma, Arkansas, Louisiana, and New Mexico, and $7.7 million in cash. The total value of the partnership redemption was $11.1 million, of which $3.4 million represented the net book value of the properties. PennTex Resources engages in the acquisition of ownership interests in oil and natural gas reserves. As of December 31, 2006, PennTex Resources owns a 25.0% non-operating working interest in approximately 1,621 active oil producing and injection wells located in the states of Illinois and Indiana, which are all operated by PennTex Illinois.

Rex I

Rex I, a Delaware limited partnership, was formed in 2002. Rex I was formed to acquire, own, operate, manage, lease, mortgage, develop, and sell or otherwise dispose of working and royalty interests in oil and gas producing properties. In January 2003, Rex I combined its assets consisting of certain producing oil and gas wells in Texas and $4.4 million in cash, with Douglas Oil & Gas, Inc., to form Douglas Oil & Gas. Rex I is a 60.55% limited partner in Douglas Oil and Gas. Rex Energy, LLC, a wholly owned subsidiary of Rex I, serves as the 1.0% owner and general partner of each of Douglas Oil & Gas and Douglas Westmoreland. LT Shaner, LLC, which is controlled by Lance T. Shaner, is the general partner of Rex I. In addition to its ownership of Douglas Oil & Gas, Rex I owns working interests in approximately 16 wells located in Fayette County, Pennsylvania.

Rex II

Rex II, a Delaware limited partnership, was formed in 2004 primarily to acquire, own, develop, lease, and sell or otherwise dispose of interests in oil and gas properties. Rex Energy II, LLC, which is controlled by Lance

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

T. Shaner, Thomas F. Shields and Benjamin W. Hulburt, is the general partner of Rex II. As of December 31, 2006, Rex II had ownership interest in approximately 165 wells located in the states of Indiana, Illinois, Texas and New Mexico. Additionally, Rex II is a member in New Albany-Indiana, LLC. See Note 25: Subsequent Events.

Rex II Alpha

Rex II Alpha, a Delaware limited partnership, was formed in 2004 primarily to acquire, own, develop, lease, and sell or otherwise dispose of interests in oil and gas properties. Rex Energy II, LLC is the general partner of Rex II Alpha, and IL Venture Capital, LLC, an unaffiliated third party, is the sole limited partner. Rex II Alpha was initially investing on a side-by-side basis in the same properties as Rex II. With the closing of the February 2006 acquisition from Wadi Petroleum, Inc., Rex II Alpha had spent all available capital contributions from its partners and was no longer able to continue investing on a side-by-side basis with Rex II. As of December 31, 2006, Rex II Alpha has ownership interests in the same 165 wells owned by Rex II.

Rex III

Rex III, a Delaware limited liability company, was formed in October 2004. Shaner Family Partners L.P. (41.85% economic interest), The Lance T. Shaner Irrevocable Grandchildren’s Trust II (4.65% economic interest), Benjamin W. Hulburt (15.0% economic interest), Thomas F. Shields (10.0% economic interest), Thomas C. Stabley (8.33% economic interest), Christopher K. Hulburt (8.33% economic interest), Michael S. Carlson (4.17% economic interest), and Jack S. Shawver (4.17% economic interest) collectively own 96.5% of the membership interests of Rex III. The remaining 3.5% membership interest in Rex III is owned by siblings of Lance T. Shaner and certain employees of Shaner Hotel Group Limited Partnership. Shaner Family Partners Limited Partnership, The Lance T. Shaner Irrevocable Grandchildren’s Trust II, and Messrs. B. Hulburt and Shields have a 45.1%, 5.1%, 24.9% and 24.9% voting interest in Rex III, respectively. In June 2006, Rex III acquired certain Illinois basin properties of Team Energy, L.L.C. and certain of its affiliates for $22.7 million. As of December 31, 2006, Rex III had ownership interest in approximately 240 wells located in the states of Indiana and Illinois.

Rex IV

Rex IV, a Delaware limited liability company, was formed in September 2006. Messrs. Shaner (50.0% economic interest), B. Hulburt (15.0% economic interest), Shields (7.0% economic interest), Stabley (7.0% economic interest), C. Hulburt (7.0% economic interest), Carlson (7.0% economic interest) and Shawver (7.0% economic interest) are the members of Rex IV. Messrs. Shaner, B. Hulburt and Shields have a 50.0%, 25.0% and 25.0% voting interest in Rex IV, respectively. Rex IV is governed by a board of managers comprised of the voting members of the company. In the event of a tie in any vote of the members, Lance T. Shaner casts the deciding vote. In October 2006, Rex IV acquired a 49.0% non-operating working interest in approximately 1,621 active oil producing and injection wells located in the states of Illinois and Indiana, which are all operated by PennTex Illinois.

Rex Operating

Rex Operating was incorporated in Delaware in 2004. Messrs. Shaner and B. Hulburt own 60.0% and 40.0%, respectively, of the outstanding common stock of Rex Operating. Rex Operating manages oil and gas properties, and provides administrative and oil and natural gas field services to the Founding Companies.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Revenue Recognition

Natural gas and oil revenue is recognized when the oil and natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. In each case it is the measurement of the purchaser that determines the amount of oil or gas purchased (although there are provisions for challenging these measurements if we believe the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil and natural gas production is at our applicable field gathering system; therefore, we do not incur transportation costs related to our sales of oil and natural gas production. The Company does not currently participate in any gas-balancing arrangements.

Transportation revenue is recognized as oil and natural gas is transported. The Company uses the allowance method to account for uncollectible accounts receivable. At December 31, 2006 and 2005 management determined the allowance for uncollectible receivables to be $172,663 and $149,556, respectively.

Profits, Losses and Distributions

All profits and losses of the Founding Companies are allocated to the stockholders, members, or partners in accordance with their percentage of equity interests in each company.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, long-term debt, a participation liability associated with long-term debt, and derivative instruments such as fixed rate swap contracts, and collars.

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

Advertising Expense

Advertising costs are expensed as incurred and equaled $38,516 and $22,571 for the years ended December 31, 2006 and 2005, respectively. Advertising costs for the year ended December 31, 2004 were insignificant.

Income Taxes

The Founding Companies are treated as partnerships and Subchapter S corporations for federal and state income tax purposes. Accordingly, income taxes are not reflected in the combined financial statements because the resulting profit or loss is included in the income tax returns of the individual stockholders, members or partners.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Oil and Gas Sale Receivables

Production receivables correspond to approximately one to two months of oil and natural gas revenue extracted and sold to buyers. The production receivable is valued at the invoiced amount and does not bear interest. The Company has assessed the financial strength of its customers and recorded bad debts as necessary.

Joint Interest Billing Receivable

Joint interest billing receivables represent the Company’s billings to the non-operators associated with the operation of wells and are based on those owners’ working interests in the wells.

Loan Costs

Loan costs consist of gross debt issuance costs of $1,752,447 and $193,598 at December 31, 2006 and 2005 that are presented net of accumulated amortization of $607,931 and $75,894, respectively. Loan costs are included in Other Assets on the Combined Balance Sheet, and will be amortized over the corresponding term of the loan they originated from, which ranges from six months to three years.

Inventory

Inventory is valued at the lower of cost or market value and consists of well tubing inventory and the Company’s ownership interest in oil held in terminal tanks located in the field. Well tubing inventory is accounted for by the first-in-first-out method. Oil inventory is accounted for using the average cost method.

Restricted Cash

The restricted cash balance for 2005 represented an account maintained as collateral on financial instruments.

Accounting Estimates

The preparation of the combined financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the combined financial statements, and the reported amounts of revenue and expenses during the reporting period. Accordingly, actual results could differ from those estimates. Among the more sensitive of the estimates involves determining the proved reserves from which depletion expense is calculated, calculating the plugging liability, and determining the future net cash flows from which asset impairment, if any, is ascertained.

Derivative Instruments

The Company uses put and call options (collars) and fixed rate swap contracts to manage price risks in connection with the sale of oil and natural gas. The Company accounts for these contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The results of these activities are reflected in the revenue section of the Combined Statements of Operations.

The Company has established the fair value of all derivative instruments using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. The values the Company reports in its combined financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

SFAS No. 133 establishes accounting and reporting standards requiring derivative instruments (including certain derivative instruments embedded in other contracts or agreements) be recorded at fair value and included

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

in the Combined Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in earnings.

For derivative instruments designated as fair value hedges (in accordance with SFAS No. 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Hedge effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. However, the Company’s evaluations are not documented, and as a result, the Company is recording changes on the derivative valuations through earnings.

Other Property and Equipment

Property, plant and equipment other than natural gas and oil properties is carried at cost. Depreciation is provided principally on the straight-line method over useful lives as follows:

Buildings and leasehold improvements	3–40 years
Furniture and equipment	5–7 years
Vehicles	5 years

Long-lived assets, such as property and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Management determined that no adjustments to the carrying value of long-lived assets were necessary for the years ended December 31, 2006, 2005 and 2004.

Maintenance and repairs are charged to expense as incurred. Major renewals and betterments are capitalized. Upon the sale or other disposition of assets, the cost and related accumulated depreciation, depletion, and amortization are removed from the accounts, the proceeds applied thereto, and any resulting gain or loss is reflected in income for the period.

Oil and Natural Gas Property, Depreciation and Depletion

The Company accounts for its natural gas and oil exploration and production activities under the successful efforts method of accounting.

Proved developed natural gas and oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of natural gas and oil are capitalized.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

The Company accounts for impairment under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future natural gas and oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Management determined that properties in 2005 and 2004 were impaired and recorded expense of $107,119 and $3,024,267, respectively, relating to the impairment.

Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

Natural Gas and Oil Reserve Quantities

The Company’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the year ended December 31, 2004, the Company had prepared reserve and economic evaluations of each of the Founding Company’s proved oil and gas reserves which has been combined to determine the Company’s total proved oil and gas reserves for the period. For the year ended December 31, 2005, the Company’s independent engineering firm, Netherland, Sewell, and Associates, Inc., prepared a reserve and economic evaluation of each of the Founding Companies’ proved oil and gas reserves which has been combined by the Company to determine the Company’s total proved oil and gas reserves for the period. For the year ended December 31, 2006, Netherland Sewell and Associates, Inc. prepared a consolidated reserve and economic evaluation of the Company’s proved oil and gas reserves.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

from these reserve estimates, in accordance with SEC guidelines. The Company’s independent engineering firm adheres to the same guidelines when preparing their reserve reports. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. Any of the assumptions inherent in these factors could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas and oil eventually recovered.

Asset Retirement Obligations

Effective January 1, 2004, the Company adopted SFAS No. 143, “Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS No. 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of the Company’s natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. The asset retirement obligation is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0%.

	2006			2005
Beginning Balance	$	2,358,158		$	1,260,428
Initial Asset Retirement Obligation Capitalized		2,506,248			1,216,570
Asset Retirement Obligation Adjustments		0			(147,599	)
Plugging Costs Incurred		(71,425	)		0
Relief of Obligation Due to Sales and Redemption		0			(170,999	)
Asset Retirement Obligation Accretion Expense		475,501			199,758
Total Asset Retirement Obligation	$	5,268,482		$	2,358,158

New Accounting Pronouncements

On March 30, 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for the Company beginning January 1, 2005, and was applied in estimating the asset retirement obligation at December 31, 2005.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies that use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling, and (3) an aging of exploratory well costs suspended for greater than one year with the number of wells it is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The pronouncement was applied by the Company when evaluating the exploratory well costs.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. The Company does not expect that adoption of this FASB Staff Position will have a material impact on its results of operations or financial position.

2. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS

Douglas Westmoreland and Rex Royalties

On February 26, 2004, Douglas Westmoreland together with Rex Royalties entered into a purchase agreement with Standard Steel, LLC (“Standard”) to acquire all of its rights, title, and interest in certain pipelines, oil and gas wells, leases, and gas purchase contracts located in Westmoreland County, Pennsylvania for a total purchase price of $4.0 million. Rex Royalties and Douglas Westmoreland have common individual partners. Douglas Westmoreland capitalized $2.5 million of the acquisition and Rex Royalties capitalized $1.5 million. Douglas Westmoreland and Rex Royalties allocated all acquisition costs to oil and gas properties.

PennTex Resources

In March 2004, PennTex Resources acquired proved oil interests in approximately 1,600 wells located in the Illinois basin for $2,750,000. PennTex Resources allocated all acquisition costs to oil and gas properties.

PennTex Illinois

Lance T. Shaner acquired 100.0% of the common stock of ERG Illinois, Inc., a Delaware Corporation, (“ERG”), from ERG Holdings, Inc. (“ERG Holdings”) effective January 1, 2005. ERG was the operator of jointly-owned oil producing properties located in the states of Illinois and Indiana and had a corresponding 26.0% working interest in those properties. Following the acquisition of common stock, ERG was renamed to PennTex Resources Illinois, Inc. The total purchase price was $5,962,000. The transaction was accounted for as a purchase, and the excess of the purchase price over the ERG equity was pushed down to the Balance Sheet of PennTex Illinois. The excess of the purchase price over the ERG reported equity of $1,460,000 was allocated to oil properties and reported as a credit to additional paid in capital. PennTex Illinois also assumed the outstanding derivative instrument liabilities (costless collars) of ERG. These derivatives had a fair value of ($1,365,000) at the acquisition date of January 1, 2005. PennTex Illinois recorded this liability at acquisition and recognized the amount as additional consideration of oil and gas properties. The purchase price allocation was as follows:

Receivables	$	1,539,463
Allowance for Doubtful Accounts		(147,209	)
Prepaid Expenses and Other		215,628
Oil Inventory		125,522
Vehicles		199,000
Producing Oil and Gas Properties		6,881,048
Payables		(562,124	)
Derivative Instrument Liabilities		(1,365,000	)
Asset Retirement Obligation		(924,000	)
Total	$	5,962,328

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

New Albany

On November 25, 2005, Rex Operating entered into a joint venture with Baseline Oil & Gas Corp., a Nevada corporation (“Baseline”) for the purpose of acquiring working interests in leasehold acreage in the Illinois Basin located in Southern Indiana known to contain New Albany Shale formations. Under this joint venture, Rex Operating, Rex Energy Wabash, LLC, and Baseline formed New Albany. At the time of formation of New Albany, Baseline had a 50.0% interest, Rex Operating had a 49.0% membership interest, and Rex Energy Wabash, LLC had a 1.0% membership interest. Rex Energy Wabash, LLC serves as the managing member of New Albany. There was no operating activity in New Albany in 2005 except for the payment of a deposit by New Albany for the purchase of leasehold interests in oil and gas properties located in the Illinois Basin. There was no income or expense in New Albany in 2005.

Rex Operating’s capital contribution to New Albany was $1,715,000, which was borrowed from Lance T. Shaner. The loan did not have a repayment term or require interest. On January 30, 2006, Rex Operating withdrew as a member from New Albany and assigned its membership interests to several of its related parties, namely Lance T. Shaner, Shaner & Hulburt Capital Partners Limited Partnership, Rex Energy II, Douglas Oil & Gas and Rex Wabash, LLC (collectively the “LLC Assignees”). Following the transfer to the LLC Assignees, Baseline continued to own a 50.0% membership interest in New Albany and the LLC Assignees together owned a 50.0% membership interest in New Albany. Of the LLC Assignees’ membership interest, Rex Wabash, LLC, a Delaware limited liability company, owns 1.0% and is the managing member of New Albany. The Company’s assignment of a 23.0287% membership interest in New Albany to Lance T. Shaner satisfied the loan made by Lance T. Shaner to Rex Operating.

Total capital contributions from New Albany’s members in 2005 were $3,500,000. These funds were used as a deposit required under the terms of a purchase agreement with Aurora Energy Ltd. (“Aurora”). In accordance with the formation agreement, New Albany can require capital contributions from its members.

In February 2006, New Albany made a capital call to its members in the amount of $6,978,770 to complete the acquisitions described above, herein referred to as the Aurora capital call. Subsequent to the Aurora capital call, New Albany made additional capital calls to its members in the amount of $5,141,500 to fund the exploration of the Aurora acquisition.

On February 1, 2006, New Albany completed an acquisition of certain oil and gas leases and other associated rights from Aurora pursuant to a Purchase and Sale Agreement with Aurora dated November 15, 2005. Under this purchase agreement, New Albany purchased from Aurora an undivided 48.75% working interest (40.7% net revenue interest) in (i) leases covering approximately 58,200 acres in several counties in Indiana (the “Leases”) and (ii) all of Aurora’s rights under a Farmout and Participation Agreement with a third party. In addition, Aurora granted an option, exercisable by New Albany until August 1, 2007, to acquire at a fixed price per acre a fifty percent (50.0%) working interest in acreage leased or acquired by Aurora or its affiliates in certain other counties located in Indiana. The total purchase price for the acquisition of the working interests in the Leases and Aurora’s rights under the Farmout Agreement, together with Aurora’s grant of the Option, was $10,500,000.

New Albany subsequently acquired, through several transactions, an additional 48.75% working interest in 63,648 gross acres as of December 31, 2006 for $1,473,462.

On March 3, 2006 New Albany completed an acquisition of certain oil and gas leases and other associated rights from Source Rock Resources, Inc. (“Source Rock”) pursuant to a Purchase and Sale Agreement with

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FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Source Rock. Pursuant to this purchase agreement, New Albany purchased from Source Rock an undivided 45.0% working interests in leases covering approximately 21,070 gross acres for $736,476. In addition, New Albany subsequently acquired through several transactions an additional 45.0% working interest in leases covering approximately 17,646 gross acres for $331,900 as of December 31, 2006.

Rex II

On August 31, 2005, Rex II acquired an 89.1% working interest from National Energy Corporation in 4 oil and gas leases covering properties located in Lawrence County, Illinois, for $1,163,646. The acquisition included interests in 37 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was July 1, 2005.

On September 19, 2005, Rex II acquired working interest ranging from 19.0% to 64.0% from Western Oil Producers, Inc. in several oil and gas leases for properties located in Eddy and Lea Counties, New Mexico, for $1,886,820. The acquisition included interests in 15 producing oil and gas wells and related infrastructure and equipment. The effective date of the acquisition was August 1, 2005. Subsequently during 2006, Rex II purchased additional, non-operating, working interests in the same properties. These interests were purchased from various sellers for approximately $1,000,000.

On September 19, 2005, Rex II acquired an 89.1% working interest from Brandt B. Powell in 3 oil and gas leases covering properties located in Lawrence County, Illinois, for $669,747. The acquisition included interests in 33 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was September 15, 2005.

On December 6, 2005, Rex II acquired a 95.5% working interest from Hux Oil Corp. and Pioneer Oil Company, Inc. in several oil and gas leases and units covering properties located in Gallatin County, Illinois and Vigo, Sullivan and Posey Counties, Indiana, for $6,756,255. The acquisition included interests in 88 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was December 1, 2005.

In June 2006, Rex II acquired a 29.4% working interest from four individuals, which is referred to as the “Scaggs Acquisition” for $1,216,597.

On January 24, 2006, Rex II acquired a 96.5% working interest from Westar Energy, Inc. in 12 oil and gas leases covering properties located in Glassrock, Midland, Reagan and Upton Counties, Texas, for $5,015,247. The acquisition included interests in 21 producing oil wells, and related infrastructure and equipment. The effective date of the acquisition was January 1, 2006.

On February 7, 2006, Rex II acquired a 48.25% working interests from Wadi Petroleum, Inc. in 62 oil and gas leases covering properties located in Terrell County, Texas, for $3,674,653. The acquisition included interests in 15 producing gas wells, and related infrastructure and equipment, including interests in a gas gathering system. The effective date of the acquisition was December 1, 2005.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Rex II allocated the purchase price for the Westar Energy, Inc. and Wadi Petroleum, Inc. acquisitions as follows:

	Westar			Wadi
Prepaid Expenses	$	7,518		$	16,014
Oil Inventory		11,566			2,234
Producing Oil and Gas Properties		5,318,875			3,700,154
Receivables and Other		0			25,454
Suspended Payables		(81,092	)		0
Asset Retirement Obligation		(241,620	)		(69,203	)
Total	$	5,015,247		$	3,674,653

In addition to the acquisitions noted above, Rex II made various smaller acquisitions throughout the year ended December 31, 2005 that amounted to approximately $800,000.

Rex II Alpha

On August 31, 2005, Rex II Alpha acquired a 9.9% working interest from National Energy Corporation in 4 oil and gas leases covering properties located in Lawrence County, Illinois, for $129,294. The acquisition included interests in 37 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was July 1, 2005.

On September 19, 2005, Rex II Alpha acquired an average 1.5% working interest from Western Oil Producers, Inc. in several oil and gas leases for properties located in Eddy and Lea Counties, New Mexico, for $189,980. The acquisition included interests in 15 producing oil and gas wells and related infrastructure and equipment. The effective date of the acquisition was August 1, 2005.

On September 19, 2005, Rex II Alpha acquired a 9.9% working interest from Brandt B. Powell in 3 oil and gas leases covering properties located in Lawrence County, Illinois, for $74,416. The acquisition included interests in 33 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was September 15, 2005.

On December 6, 2005, Rex II Alpha acquired a 3.0% working interest from Hux Oil Corp. and Pioneer Oil Company, Inc. in several oil and gas leases and units covering properties located in Gallatin County, Illinois and Vigo, Sullivan and Posey Counties, Indiana, for $210,000. The acquisition included interests in 88 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was December 1, 2005.

On January 24, 2006, Rex II Alpha acquired an average 3.0% working interest from Westar Energy, Inc in 12 oil and gas leases covering properties located in Glassrock, Midland, Reagan and Upton Counties, Texas, for $160,000. The acquisition included interests in 21 producing oil wells, and related infrastructure and equipment. The effective date of the acquisition was January 1, 2006.

On February 7, 2006, Rex II Alpha acquired an average 1.5% working interests from Wadi Petroleum, Inc. in 62 oil and gas leases covering properties located in Terrell County, Texas, for $150,000. The acquisition included interests in 15 producing gas wells, and related infrastructure and equipment, including interests in a gas gathering system. The effective date of the acquisition was December 1, 2005.

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FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Rex III

On June 28, 2006, Rex III acquired average working interests of 72.0% in approximately 220 producing oil wells and related infrastructure and equipment located in Posey and Gibson Counties, Indiana, and Lawrence County, Illinois from Team Energy, L.L.C., an Illinois limited liability company (“Team Energy”) and certain other companies affiliated with Team Energy. The effective date of the acquisition was June 1, 2006. The total acquisition price was $22,701,639. Rex III allocated the purchase price as follows:

Producing Oil and Gas Properties	$	21,874,426
Building and Real Estate		825,770
Oil Inventory		101,884
Vehicles and Equipment		488,000
Asset Retirement Obligation		(593,027	)
Prepaid/Accrued Expenses		4,586
Total	$	22,701,639

Rex IV

On October 3, 2006, Rex IV acquired average working interests of 49.0% in certain oil producing properties and related wells and equipment located in the Lawrence, West Kenner, and St. James fields in Illinois, and the El Nora field in Indiana (the “Illinois and Indiana Properties”) for $35,171,970 from TSAR Energy II, L.L.C. (“Tsar”). The effective date of the acquisition was October 1, 2006. PennTex Resources and PennTex Illinois, companies affiliated with Rex IV, own average working interests of 25.0% and 26.0%, respectively, in the Illinois and Indiana Properties. PennTex Illinois is the operator of the Illinois and Indiana Properties. The acquisition of the working interest of Tsar in the Illinois and Indiana Properties by Rex IV was accounted for as a purchase.

Rex IV allocated the purchase price as follows:

Producing Oil Properties	$	36,595,479
Oil Inventory		112,433
Asset Retirement Obligation		(1,485,122	)
Accrued Real Estate Taxes		(50,820	)
Total	$	35,171,970

3. CONCENTRATION OF CREDIT RISKS

At times during the year ended December 31, 2006 and 2005, the Company’s cash balance may have exceeded the Federal Deposit Insurance Corporation insured limit of $100,000. There were no losses incurred due to concentrations.

By using derivative instruments to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative is positive, the counterparty owes the Company, which creates repayment risk. The Company minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.

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FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

4. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value of the Company’s long-term debt instruments approximates the fair value as the debt facilities carry a market rate of interest.

The Company estimates the fair value of the participation liability associated with Norguard Insurance Company’s term loan to be $2,141,109 and $574,254 as of December 31, 2006 and 2005, respectively.

The fair value of the net liability associated with the Company’s derivative instruments was $3,258,102 and $8,301,322 at December 31, 2006 and 2005, respectively. The fair value is based on valuation methodologies of the Company’s counterparties. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

5. COMMITMENTS AND CONTINGENCIES

Legal Reserves

At December 31, 2006, the Company’s Combined Balance Sheet included reserves for the legal proceedings detailed in Note 24: Litigation of $891,000. The accrual of reserves for legal matters is included in Accrued Expenses on the Combined Balance Sheet. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional loss, the amount of which is not currently estimable, in excess of the amounts currently accrued with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in actual liability exceeding the estimated ranges of loss and the amounts accrued. Based on currently available information, the Company believes that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed current accruals by an amount that would have a material adverse effect on the combined financial position or results of operations of the Company, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

Environmental

Due to the nature of the natural gas and oil business, the Company is exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. It conducts periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort. The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. Except as described in Note 24: Litigation, management knows of no significant probable or possible environmental contingent liabilities.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Contract Wells

In March 2004, Douglas Westmoreland purchased from Standard Steel, LLC certain contractual rights associated with various gas purchase contracts relating to 19 natural gas wells. Under the terms of the contracts Douglas Westmoreland buys 100.0% of production from these wells from third parties at contracted, fixed prices. The prices it pays range from $1.10 per Mcf to 55.0% of the market price, plus a $0.10 per Mcf surcharge. There is no loss on these commitments. The Company has recorded the gross revenue and costs in the Combined Statements of Operations. Douglas Westmoreland sells the natural gas extracted from these contract wells to parties unrelated to these natural gas wells and contracts.

Letters of Credit

Douglas Westmoreland has posted a $50,000 letter of credit with the Commonwealth of Pennsylvania to secure its drilling and related operations on Keystone State Park in Westmoreland County, Pennsylvania.

Other

In addition to the Asset Retirement Obligation discussed in Note 1, Douglas Oil & Gas has withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. Such amounts totaling $325,036 are included in Other Liabilities at December 31, 2006 and 2005.

6. LINES OF CREDIT

Douglas Oil & Gas

On October 28, 2004, Douglas Oil & Gas executed a revolving line of credit agreement with Guaranty Bank. The line of credit was to mature on October 28, 2007. Accrued and unpaid interest on the aggregate outstanding line of credit balance was due monthly. The line of credit accrued monthly interest on the floating rate, which is defined at the Company’s base rate plus 1.25%. The amount outstanding on the line of credit at December 31, 2005 was $3,292,755. All outstanding borrowings under the Guaranty Bank line of credit were repaid by the proceeds of the M&T Bank Term Loan described in Note 7: Long- Term Debt.

Rex IV

Rex IV entered into a Credit Agreement dated as of October 2, 2006 with KeyBank National Association (“KeyBank”), as Administrative Agent on behalf of signatory lenders which are parties to the agreement from time to time. The credit facility established under the Credit Agreement provides for loans and letters of credit of up to a maximum of $40,000,000. Under the credit facility, Rex IV may borrow funds under an alternative base rate or Eurodollar rate. Under the alternative base rate, Rex IV may borrow funds at a rate per annum equal to the greater of (i) the prime rate in effect on such day (which is defined as the rate of interest per annum publicly announced from time to time by KeyBank as its prime rate in effect at its principal office) and (ii) the Federal Funds Effective Rate (which is defined as the weighted average of the rates on overnight Federal fund transactions with members of the Federal Reserve System) in effect on such day plus  ¹/2 of 1.0%. Under the Eurodollar rate, Rex IV may borrow funds a rate per annum equal to the LIBO rate for such period multiplied by the statutory reserve rate. The statutory reserve rate is calculated as a fraction, the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the applicable maximum reserve percentages expressed as a decimal established by the Federal Reserve Board for eurocurrency funding.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Borrowings under the new credit facility mature on the earlier to occur of (i) the next business day following the closing date of a new senior credit facility to be entered into by an affiliate of Rex IV pursuant to that certain commitment letter between Rex Operating and KeyBank dated September 29, 2006, (ii) the next business day following the date of the issuance of equity interests by Rex IV or another Founding Company in an initial public offering or (iii) April 2, 2007. Provided that certain conditions under the credit agreement are met, Rex IV may at any time and from time to time repay outstanding borrowings under the new credit facility, in whole or in part. See Note 25: Subsequent Events.

Borrowings under the new credit facility are currently secured by all of the Rex IV’s oil and gas properties, including the Illinois and Indiana Properties described in Note 1. The Credit Agreement requires that at all times assets secured under the credit agreement represent at least 75.0% of the total value of Rex IV’s oil and gas properties. The Credit Agreement requires Rex IV to meet certain quarterly financial covenants and ratios, including total debt to EBITDAX (which is defined as consolidated net income plus expenses and charges, to the extent deducted from consolidated net income, of interest, income taxes, depreciation, depletion, amortization, exploration expenses and other similar noncash charges, minus all noncash income added to consolidated net income), and consolidated current assets to consolidated current liabilities. In addition, Rex IV must meet certain requirements regarding quarterly and annual financial reporting and semi-annual oil and gas reserve reporting. The Credit Agreement also contains non-financial covenants, which restrict the action of Rex IV with respect to certain matters, including the incurrence of additional indebtedness, payment of dividends and distributions, sale of the Rex IV’s assets, the making of investments, transactions with affiliated companies, and the creation of additional liens on the assets of Rex IV.

The Credit Agreement requires that if either (i) Rex IV has not obtained a commitment for financing sufficient to fully and timely repay borrowings under the credit facility or (ii) if the borrowings under the credit facility have not been paid in full by March 12, 2007, upon notice by the administrative agent, Rex IV must cause the issuance and sale of its subordinated notes on a date which is no later than April 2, 2007 upon such terms and conditions as specified by the administrative agent. The proceeds of the subordinated notes must be used to repay borrowings under the new credit facility. The interest rates for the subordinated notes (whether floating or fixed) will be determined by the administrative agent with the approval of Rex IV (such approval not to be unreasonably withheld or delayed) in light of the then prevailing market conditions for comparable securities of comparable issuers. All other arrangements with respect to the subordinated notes must be reasonably satisfactory in all respects to the administrative agent in light of the then prevailing market conditions and the net cash proceeds of the sale of such subordinated notes must be sufficient to repay all amounts due under the Credit Agreement.

On October 1, 2006, Rex IV borrowed $36,580,634 under the new credit facility to pay the purchase price for the acquisition of the Illinois and Indiana Properties from Tsar. At December 31, 2006, the outstanding balance on the line of credit was $37,580,634, of which $37,000,000 incurred interest at 8.35% and $580,634 incurred interest at 10.25%.

As of December 31, 2006, Rex IV was not in compliance with the negative covenant in its credit agreement requiring that its ratio of total debt to EBITDAX, as defined above, shall not exceed 5.5:1. On March 9, 2007, Rex IV obtained a written waiver from KeyBank of this covenant for the fourth quarter of 2006. See Note 25: Subsequent Events.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

PennTex Resources

On December 14, 2004, PennTex Resources entered into a $50 million line of credit facility with Guaranty Bank. As of December 31, 2004, the total borrowing base under the line of credit was $6,000,000. The borrowing base was determined semi-annually by Guaranty Bank according to the provisions of the agreement. All of PennTex Resources oil and natural gas assets secured the line of credit. The line of credit was to mature in December 2007 and required interest on a floating rate of prime plus 1.25%, which was 8.5% at December 31, 2005. The ending balance as of December 31, 2005 on the line of credit was $2,549,016, which represented the determined borrowing base. All outstanding borrowings under the Guaranty Bank line of credit were repaid by the proceeds of the M&T Bank revolving line of credit described in Note 7: Long-Term Debt.

7. LONG-TERM DEBT

Douglas Westmoreland Term Loan—Norguard

On March 22, 2004, Douglas Westmoreland entered into a loan agreement with Norguard Insurance Company (“Norguard”) in the amount of $2.5 million. In November 2004, in accordance with the term loan agreement, the loan was increased to $3.0 million. The debt proceeds were used by Douglas Westmoreland to finance the acquisition of natural gas properties located in Westmoreland County, Pennsylvania from Standard Steel, LLC and for well and pipeline development. The term loan was secured by all of Douglas Westmoreland’s natural gas properties. The loan earned interest at a fixed-rate of 8.0% and matured on June 1, 2009. The loan also included a 20.0% contingent interest component applied on excess cash flow. Monthly installments of interest only were payable until the maturity date.

The contingent interest component associated with the loan from Norguard has been accounted for in accordance with AICPA Statement of Position 97-1, “Accounting by Participating Mortgage Loan Borrowers” (“SOP 97-1”)

For the years ended December 31, 2006 and 2005, Douglas Westmoreland recognized a participation liability related to the contingent component associated with the Norguard term loan in accordance with SOP 97-1. This participation liability is reflected in the liability section of the Combined Balance Sheets. Douglas Westmoreland estimated the fair value of the participation liability to be $574,254 as of December 31, 2005. In 2006, the fair value of the participation liability was estimated to be $2,141,109. The estimated fair value of the participation liability represents a 20.0% interest of Douglas Westmoreland’s net present value of future cash inflows derived from its natural gas reserves. Douglas Westmoreland utilized a present value factor of 10.0 when estimating the participation liability for the year ended December 31, 2006.

On February 13, 2006, Douglas Westmoreland repaid the outstanding principal amount of the loan with Norguard with the proceeds of the loan with M&T Bank described below. Norguard retained its 20.0% contingent interest in Douglas Westmoreland’s excess cash flows following the February 13, 2006 repayment of the loan. Contingent interest continues to be due in quarterly installments.

Douglas Oil & Gas and Douglas Westmoreland Term Loan —M&T Bank

On February 13, 2006, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, entered into a revolving line of credit of up to $10,000,000 with Manufacturers and Traders Trust Company, as agent (the “Douglas M&T Loan”). The Borrowing Base for the Douglas M&T Loan as of December 31, 2006 was $9,500,000. Effective January 12, 2007, the Borrowing Base increased to $10,000,000. Interest on the loan

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

accrues and is payable at a rate per annum equal to the base rate from time to time in effect, plus one percent (1.0%). The base rate is equal to the rate of interest per annum then most recently established by M&T Bank as its “prime rate”, which rate may not be the lowest rate of interest charged by M&T Bank to its borrowers. Interest is calculated on unpaid sums actually advanced and outstanding and only for the period from the date or dates of such advances until repayment. Accrued and unpaid interest on aggregate outstanding balances is due monthly and commenced in February 2006. There are no principal payments due monthly. The loan matures on February 13, 2009. The borrowers are jointly and severally liable with respect to borrowings under the Douglas M&T Loan.

Each borrower has guaranteed the full and timely payment by the other borrower of each and every obligation and liability of such other borrower to the lenders. In addition, borrowings under the loan are guaranteed, in specified percentages, by Douglas Oil & Gas, Inc., its stockholders, and Lance T. Shaner. The Douglas M&T Loan is secured by each of the borrower’s assets and oil and gas producing properties located in the Commonwealth of Pennsylvania and in the states of New Mexico and Texas. Borrowings from the Douglas M&T Loan were used to repay all borrowings of Douglas Oil & Gas under a reducing revolving line of credit of up to $50,000,000 with Guaranty Bank, FSB. Borrowings under the Douglas M&T Loan were also used to repay the $3,000,000 term loan with Norguard. See Note 6: Lines of Credit. The outstanding balance on the Douglas M&T Term Loan as of December 31, 2006 is $8,941,586 and the interest rate is 9.25%.

As of December 31, 2006, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, were not in compliance with the negative covenant in the credit agreement for the Douglas M&T Loan which states that the co-borrowers will not permit their tangible net worth, on a combined basis, as of the end of any fiscal year to be less than such amount that is 15.0% less than the tangible net worth of the co-borrowers as indicated on their audited year end financial statements as of December 31, 2005; provided, however, that commencing on December 31, 2006, and at the end of each fiscal year thereafter, this amount will increase by $500,000. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarters of 2007.

PennTex Illinois and PennTex Resources Credit Facility—M&T Bank

On January 19, 2006, PennTex Illinois and PennTex Resources, as co-borrowers, entered into a revolving line of credit of up to $22,500,000 with Manufacturers and Traders Trust Company, as agent (the “PennTex M&T Credit Facility”). The Borrowing Base for the PennTex M&T Credit Facility was $18,500,000 as of December 31, 2006. Interest on the credit facility accrues and is payable at a rate per annum equal to the base rate from time to time in effect, plus one percent (1.0%). The base rate is equal to the rate of interest per annum then most recently established by M&T Bank as its “prime rate”, which rate may not be the lowest rate of interest charged by M&T Bank to its borrowers. Interest is calculated on unpaid sums actually advanced and outstanding and only for the period from the date or dates of such advances until repayment. There are no principal payments due monthly. The borrowers are jointly and severally liable with respect to borrowings under the PennTex M&T Credit Facility. Each borrower has guaranteed the full and timely payment by the other borrower of each and every obligation and liability of such other borrower to the lenders. In addition, borrowings under the credit facility are guaranteed by the co-borrowers’ sole owner, Lance T. Shaner. The PennTex M&T Credit Facility is secured by each of the borrower’s assets and oil producing properties located in the states of Illinois and Indiana. The credit facility matures on January 16, 2009. The interest rate on the line of credit as of December 31, 2006 was 9.25% and the outstanding balance was $14,944,536.

As of December 31, 2006, PennTex Illinois and PennTex Resources, as co-borrowers, were not in compliance with the negative covenant in their credit agreement requiring that their ratio of current assets to

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

current liabilities, as defined in the credit agreement, be at lease 1.1:1. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarters of 2007.

Rex II Credit Facility—Sovereign Bank

On March 24, 2006, Rex II entered into a revolving line of credit for up to $3,700,000 with Sovereign Bank. Interest on the loan accrues and is equal to the rate of interest per annum from time to time established by Sovereign Bank as its prime rate of interest. The loan matures on March 24, 2008. Draws on the line were used to fund acquisitions and development costs associated with Rex II’s oil and gas properties. The outstanding balance on the line of credit was $3,550,149 as of December 31, 2006, bearing interest at a rate equal to 8.75%. On February 13, 2007, all outstanding borrowings under the revolving line of credit were refinanced and became outstanding obligations under the Rex II’s Amended and Restated Credit Facility with Sovereign Bank. See Note 25: Subsequent Events.

Rex III Credit Agreement—M&T Bank

On June 28, 2006, Rex III entered into a Credit Agreement with Manufacturers and Traders Trust Company (“M&T Bank”), as Letter of Credit Issuer, Lead Arranger and Agent on behalf of signatory lenders which are parties to the agreement from time to time. The credit facility established under the Credit Agreement provides for loans and letters of credit of up to a maximum of $20,000,000. The Credit Agreement provides for a revolving credit loan up to a maximum of $15,000,000 and for term loans in the amount of up to $5,000,000. Interest on each advance under the revolving credit loan and the term loans accrues and is payable at a rate per annum selected by Rex III at either a LIBOR based rate or the applicable floating rate. Under the LIBOR based rate option, Rex III may borrow funds under the revolving credit loan at a rate per annum equal to LIBOR plus 3.0% and under the term loans at a rate per annum equal to LIBOR plus 5.50%. Under the applicable floating rate option, Rex III may borrow funds under the revolving credit loan at a rate per annum equal to the Base Rate from time to time in effect plus 0.75%, and under term loans at a rate per annum equal to the Base Rate from time to time in effect plus 3.25%. The Base Rate is defined as the rate of interest per annum then most recently established by M&T Bank as its “prime rate” of interest. Until the maturity date, only monthly payments of interest are required regarding borrowings under the revolving credit loan. As of December 31, 2006, the interest rate associated with the revolving credit loan and term loan was 8.32% and 10.82%, respectively.

The revolving credit loan terminates on June 27, 2009. The aggregate outstanding principal balance of the revolving credit loans, together with all accrued but unpaid interest thereon is due and payable on the termination date. The term loan matures on December 27, 2008. The principal balance of the term loans is payable as follows:

Payment Date	Principal Amount Due
June 27, 2007	$   625,000.00
December 27, 2007	$1,250,000.00
June 27, 2008	$1,250,000.00
December 27, 2008	The lesser of $1,875,000.00 or the then outstanding principal balance of the term loans.

Rex III Credit Agreement—M&T Bank

Provided that certain conditions under the credit agreement are met, Rex III may at any time and from time to time repay outstanding borrowings under the new credit facility, in whole or in part, without prepayment penalty, provided that such prepayments must be in minimum amounts of $100,000.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Borrowings under the new credit facility are currently secured by all of Rex III’s oil and gas properties, including the properties acquired by Rex III from Team Energy. The Credit Agreement requires Rex III to meet certain quarterly financial covenants and ratios, including current assets to current liabilities, minimum asset coverage ratio of total reserve value to total funded debt, minimum fixed charge coverage ratio and total funded debt to EBITDA ratios. In addition, Rex III must meet certain requirements regarding quarterly and annual financial reporting and semi-annual oil and gas reserve reporting. The Credit Agreement also contains non-financial covenants, which restrict the action of Rex III with respect to certain matters, including the incurrence of additional indebtedness, payment of dividends and distributions, sale of Rex III’s assets, the making of investments and loans, changes in structure of Rex III, transactions with affiliated companies, and the creation of additional liens on the assets of Rex III.

On June 28, 2006, Rex III borrowed $20,000,000 under the new credit facility to pay the purchase price for the acquisition of oil and gas properties of Team Energy and affiliated companies. Of this amount, $15,000,000 was borrowed under the revolving credit loan and $5,000,000 was borrowed under the term loan portion of the facility. At December 31, 2006, outstanding borrowings under the new credit facility were $20,000,000, of which $15,000,000 was under the revolving credit loan and $5,000,000 was under the term loan.

As of December 31, 2006, Rex III was not in compliance with the negative covenant contained in its credit agreement requiring that its ratio of total reserve value to total funded debt, as defined in the credit agreement, be at least 2.5:1. Rex III obtained a written waiver from its lenders regarding its non-compliance with this negative covenant for the fourth quarter of 2006 and the first and second quarter of 2007.

8. OTHER LOANS AND NOTES PAYABLE

Douglas Oil & Gas Vehicle Loans

Douglas Oil & Gas obtained $125,068 in loans to obtain 4 vehicles used in operations. The interest rates on the loans range from 6.24% to 8.49%. The loans mature in 2009 and 2010. The outstanding balance on these vehicles loans is $96,421 and $111,474 at December 31, 2006 and 2005, respectively.

Douglas Westmoreland Vehicle Loan

Douglas Westmoreland obtained a loan to obtain a vehicle used in operations. The interest rate on the loan is 9.15%. The loan matures in June 2010. The outstanding balance on this vehicle loan is $19,832 and $23,254 at December 2006 and 2005, respectively.

PennTex Illinois Vehicle Loan

PennTex Illinois obtained a loan in 2005 in the amount of $367,267 to acquire approximately fifteen trucks used for field operations. The loan matures in June 2009 and incurs interest at 6.24%. The outstanding balance on the vehicle loan is $239,252 and $316,293 at December 31, 2006 and 2005, respectively.

Rex Operating Loans and Notes Payable

Rex Operating has various loans and notes payable outstanding as of December 31, 2006 and 2005. The loans and notes payable consist of the following at December 31

a. A 2005 vehicle loan requiring payments of principal and interest at 7.24%. The loan matures in August 2009. The outstanding balance on the vehicle loan is $20,145 and $30,543 at December 31, 2006 and 2005, respectively.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

b. A 2006 vehicle loan requiring payments of principal and interest at 7.0%. The loan matures in March 2009. The outstanding balance on the vehicle loan is $26,894 at December 31, 2006.

c. A 2006 loan to finance the purchase of copier equipment. This loan requires payments of principal and interest at 7.5%. The loan matures in April 2009. The outstanding balance on the copier loan is $12,741 at December 31, 2006.

d. In 2006, Rex Operating acquired new oil and gas accounting software (“Enertia”) in the amount of $446,590. The Company financed this software with a note payable to the vendor. Rex Operating made an initial down payment of $50,000 toward the note payable in March 2006. Beginning May 2006, this note payable requires payments of principal and interest at 7.5%. The note payable matures in October 2007. The outstanding balance on the note payable is $205,127 at December 31, 2006.

e. During 2006, Rex Operating moved its headquarters to a 5,270 square foot building owned by Shaner Brothers, LLC (a related party). Rex Operating financed the construction of leasehold improvements with a note payable to Shaner Brothers, LLC in the amount of $264,656. The note payable was effective in October 2006. The note payable requires payments of principal and interest at 7.0%. The note payable matures in September 2011. The outstanding balance on the note payable is $253,501 at December 31, 2006.

9. FUTURE MINIMUM REPAYMENTS

Future minimum repayments of the Founding Companies’, lines of credit, long-term debts, and other loans and notes payable are as follows:

2007	$	40,448,174
2008		8,075,268
2009		37,233,802
2010		82,794
2011		50,780
Thereafter		0
Total	$	85,890,818

10. FINANCIAL DERIVATIVE INSTRUMENTS

The Company’s results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, the Company entered into oil and natural gas derivative instruments. As of December 31, 2006, 2005 and 2004, the Company’s oil and natural gas derivative instruments consisted of fixed rate swap contracts and collars. These instruments allow the Company to predict with greater certainty the effective oil and natural gas price to be received for the Company’s hedged production.

Collars contain a fixed floor price (put) and ceiling price (call). The put options are purchased from the counterparty by the Company’s payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays the Company an amount equal to the product of the

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty by the Company’s receipt of a cash premium. If the market price is greater than the call strike price for a calculation period, then the Company pays the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.

The Company sells oil and natural gas in the normal course of business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in oil and natural gas sales. The Company enters into derivative instruments such as swap contracts to hedge a portion of its forecasted oil and natural gas sales.

The Company received (incurred) net payments of ($4,436,347), ($7,929,478) and ($941,511) under these derivative instruments during years ended December 31, 2006, 2005, and 2004, respectively. Unrealized gains (losses) associated with these derivative instruments are included in operating revenue and amounted to $5,043,220, ($5,541,043), and ($1,395,531) for the years ended December 31, 2006, 2005, and 2004, respectively.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

The Company’s open asset/ (liability) financial derivative instrument positions at December 31, 2006 consisted of:

Derivative Instrument	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Put/ Floor Price		Call/ Ceiling Price		Fixed Price		Fair Market Value
Swap Contracts	0	9,000	1/07-9/07	$	0	$	0	$	59.75	$	(22,078	)
Swap Contracts	0	36,000	1/07-12/07	$	0	$	0	$	64.75		2,351
Swap Contracts	120,000	0	1/07-12/07	$	0	$	0	$	7.54		67,059
Swap Contracts	0	216,000	1/07-12/07	$	0	$	0	$	65.00		15,633
Collars	0	96,000	1/07-12/07	$	40.00	$	42.55	$	0		(2,098,391	)
Collars	0	32,000	1/07-4/07	$	34.00	$	38.35	$	0		(777,379	)
Collars	480,000	0	1/07-12/07	$	8.00	$	14.65	$	0		735,675
Collars	0	48,000	1/07-12/07	$	55.00	$	61.25	$	0		(249,170	)
Collars	0	24,000	1/07-12/07	$	70.00	$	82.60	$	0		163,903
Collars	120,000	0	1/07-12/07	$	7.00	$	15.05	$	0		101,948
Collars	0	24,000	1/07-12/07	$	70.00	$	83.75	$	0		165,980
Collars	0	96,000	1/07-12/07	$	65.00	$	76.00	$	0		289,518
Collars	0	56,000	5/07-12/07	$	50.00	$	70.34	$	0		(98,881	)
Total Current Portion	720,000	637,000								$	(1,703,832	)
Swap Contracts	0	204,000	1/08-12/08	$	0	$	0	$	65.58		(252,948	)
Swap Contracts	0	192,000	1/09-12/09	$	0	$	0	$	64.00		(426,433	)
Swap Contracts	0	180,000	1/10-12/10	$	0	$	0	$	62.20		(541,519	)
Collars	0	49,002	1/08-7/08	$	62.00	$	70.00	$	0		(58,266	)
Collars	0	144,000	1/08-12/08	$	60.00	$	89.25	$	0		369,889
Collars	600,000	0	1/08-12/08	$	7.00	$	9.35	$	0		(140,183	)
Collars	0	56,000	1/08-7/09	$	65.00	$	76.00	$	0		108,082
Collars	0	55,000	2/08-12/08	$	65.00	$	80.20	$	0		157,722
Collars	0	60,000	8/08-12/08	$	65.00	$	76.05	$	0		119,792
Collars	0	10,000	8/08-12/08	$	62.00	$	70.00	$	0		(16,623	)
Collars	0	30,000	8/08-12/08	$	62.00	$	69.10	$	0		(49,871	)
Collars	0	175,001	1/09-7/09	$	62.00	$	67.80	$	0		(361,600	)
Collars	120,000	0	1/09-2/09	$	7.00	$	9.00	$	0		(21,830	)
Collars	0	140,004	8/09-12/09	$	62.00	$	66.10	$	0		(353,162	)
Collars	480,000	0	1/09-12/09	$	7.00	$	9.35	$	0		(87,320	)
Total Long-Term Portion	1,200,000	1,295,007								$	(1,554,270	)
Total Derivative Instruments	1,920,000	1,932,007								$	(3,258,102	)

11. RELATED PARTY TRANSACTIONS

New Albany

See Note 2: Business and Oil and Gas Property Acquisitions.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

PennTex Illinois

During 2005, PennTex Illinois obtained two working capital loans from two related parties for a total of $1,400,000. The loans incurred interest at a rate of 13.0%. The total interest expense associated with the loans was $118,118. There was no outstanding balance on either loan at December 31, 2005.

At December 31, 2005, there was an accrued distribution owed to Lance T. Shaner in the amount of $3,100,000 which was paid in January of 2006. Lance T. Shaner owns 100.0% of the common stock of PennTex Illinois.

At December 31, 2005, there was a receivable due from Lance T. Shaner in the amount of $700,000 with no term or due date. This amount was repaid in January 2006.

At December 31, 2006, there was a working capital loan payable to Lance T. Shaner in the amount of $1,820,000 with no term or due date.

PennTex Resources

PennTex Resources transferred ownership of a well recorded at $170,043 to Lance T. Shaner in 2005. This transfer reduced the related party payable due to Lance T. Shaner by an equal amount. There is no gain recorded by the Company on this distribution.

PennTex Resources repaid an outstanding debt to Lance T. Shaner in the amount of $8,136,423 during the year ended December 31, 2006.

See Note 12: Partnership Redemption.

Rex I

Included in Other Assets is a $20,000 investment in an unconsolidated related party, which represents Rex I’s 100.0% membership interest in Rex Energy, LLC.

Rex II

As of December 31, 2005, $139,500 of capital contributions receivable were due from related parties. The outstanding capital contributions were paid during 2006.

Refer to Note 1: Principles Combination and Reporting for additional related party information.

Rex Royalties

At December 31, 2005, there was an accrued distribution owed to Shaner & Hulburt Capital Partners in the amount of $30,000 which was paid in January 2006.

Rex Operating

Pursuant to an oral month-to-month lease agreement, Rex Operating leased approximately 3,725 square feet of office space from Shaner Brothers, LLC at a fixed rental rate of $5,000 per month from inception of Rex Operating until September 1, 2006. Shaner Brothers, LLC is a Pennsylvania limited liability company which is

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

currently owned by Lance T. Shaner, a 60.0% shareholder of Rex Operating, and Shaner Family Partners Limited Partnership, a Pennsylvania limited partnership controlled by Lance T. Shaner (“Shaner Brothers”). On September 1, 2006 this oral month-to-month lease agreement terminated.

Beginning on September 1, 2006, Rex Operating leased approximately 5,270 square feet of office space from Shaner Brothers. This office space is located at the Company’s current headquarters at 1975 Waddle Road, State College, Pennsylvania. Rex Operating currently leases this office space pursuant to a written lease agreement that provides for an initial term of three years, expiring on August 31, 2009. The lease agreement requires the payment of rent in the amount of $7,908 per month, subject to adjustment on each anniversary date of the lease in accordance with the percentage of increase in the Consumer Price Index for the U.S. for Urban Consumers (CPI-U) for the preceding year (the “CPI Adjustment”). The monthly rent is also subject to adjustment in the form of additional monthly rent which is calculated annually and equal to the percentage of increase of Shaner Brother’s costs for taxes, insurance premiums and operating expenses for the previous year (the “Additional Monthly Rent”). The annual monthly rent adjustment resulting from the CPI Adjustment and Additional Monthly Rent may not in the aggregate exceed a three percent increase over the prior lease year. Under the terms of the lease, Rex Operating is responsible for certain costs relating to the interior construction of the building and the payment of all utilities, cleaning expenses, maintenance and other related costs and expenses of the building resulting from the Company’s operation, use and occupancy of the premises. Following the expiration of the initial term, Rex Operating may renew the lease for up to 3 one-year extensions upon written notice to Shaner Brothers at least 120 days, but no more than 6 months, prior to the expiration of the current term. The Company believes that the terms of this lease are comparable to terms that could be obtained at an arms’ length basis in the State College, Pennsylvania area for leases of similar office space.

On September 1, 2006, Shaner Brothers loaned $264,656 to Rex Operating to fund its expenses relating to the construction of the interior portions of its headquarters office building. This loan is evidenced by an unsecured promissory note dated September 1, 2006. The promissory note provides for the payment of interest on the unpaid principal sum at a rate of 7.0% per annum. The loan must be repaid in 60 consecutive equal monthly installments of principal and interest in the amount of $5,240. The promissory note matures on September 1, 2011, but may be prepaid in whole or in part at anytime, without premium or penalty. At December 31, 2006, the outstanding principal amount of the loan was $253,501. The Company believes that the terms of this loan are comparable to terms that could be obtained at an arms’ length basis from unrelated lenders.

Rex Operating obtains certain administrative services (such as human resources, information technology, payroll, and tax services) from Shaner Solutions Limited Partnership, a Delaware limited partnership controlled by Lance T. Shaner (“Shaner Solutions”), pursuant to an oral month-to-month agreement providing for a monthly fee of $15,000, plus reimbursement for Shaner Solutions’ reasonable out-of-pocket expenses. The Company believes that the amount charged by Shaner Solutions is comparable to rates obtainable at an arm’s length basis in the State College, Pennsylvania area for similar services.

Rex Operating has an oral month-to-month agreement with Charlie Brown Air Corp., a New York corporation owned by Lance T. Shaner (“Charlie Brown”), regarding the use of two airplanes owned by Charlie Brown. Under Rex Operating’s agreement with Charlie Brown, Rex Operating pays a monthly fee for the right to use the airplanes equal to its percentage (based upon the total number of hours of use of the airplanes by the Company) of the monthly fixed costs for the airplane, plus a variable per hour flight rate of $1,350 per hour. The Company believes that the terms of this agreement are comparable to terms that could be obtained at an arms’ length basis in the State College, Pennsylvania area for similar private aircraft services.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

During the year ended December 31, 2005, Rex Operating borrowed $1,715,000 from Lance T. Shaner to finance its capital contribution to New Albany. At December 31, 2005 the outstanding balance was $1,715,000. As described in Note 2: Business and Oil and Gas Property Acquisitions, this loan was satisfied by Rex Operating’s assignment of a 23.0287% membership interest in New Albany during the year ended December 31, 2006.

Rex Operating—Employee Receivables

Receivables from employees as of December 31, 2005 were $253,213. Of this amount, $155,222 represents advances to employees so they could purchase oil and gas properties associated with Rex II. All of the amounts advanced to purchase properties were repaid in 2006.

The remaining balance of $97,991 at December 31, 2005 represents the outstanding balance on other loans to three employees. These loans are in the form of prepaid compensation. A total of $130,000 was loaned to these three employees in 2005. The loans are forgiven if the employees continue to be employed by the Company over periods ranging from 3 to 5 years. The loans will be expensed over the 3 to 5 year service terms. If the employee’s employment with the Company is terminated for any reason, the outstanding balance of the loan is immediately due and payable. In 2006 and 2005, the expense recognized for the portion of the loan forgiven was $32,667 and $32,667, respectively. The balance of these loans was $64,667 at December 31, 2006.

Employee receivables at December 31, 2006 also include $32,817 for amounts advanced to fund employees’ health savings accounts, which will be repaid through payroll withholdings throughout the year.

Other

Other related party transactions of the Founding Companies were insignificant at December 31, 2006 and 2005.

12. PARTNERSHIP REDEMPTION

PennTex Resources

On October 17, 2005, PennTex Resources redeemed the 40.0% limited partnership interest of Thomas J. Taylor in PennTex Resources. The redemption price was paid, in part, in the form of a distribution to Mr. Taylor of all of the Company’s oil and gas producing properties in the states of Texas, Oklahoma, New Mexico, Arkansas, and Louisiana. The distribution of producing properties did not include PennTex Resources’ jointly-owned oil producing properties located in the states of Illinois and Indiana.

The value of the partnership redemption was $11,425,398. Of this amount, $7,666,540 was distributed to Thomas J. Taylor in the form of cash. A distribution of net book value of property in the amount of $3,758,926 was also made. The cash distribution was financed by a personal loan to the Company from Lance T. Shaner. This loan had no term, no interest rate, and no interest was paid. The loan was repaid in January of 2006 with the proceeds of the PennTex M&T credit facility described in Note 7: Long-Term Debt.

New Albany

See Note 25: Subsequent Events

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

13. MAJOR CUSTOMERS

All of the natural gas extracted from Douglas Westmoreland’s wells was sold to Dominion Exploration and Production, Inc. or Dominion Peoples, Inc. in 2006, 2005, and 2004.

All of the natural gas extracted from wells in which Rex Royalties owns royalty interests is sold to Dominion Exploration and Production, Inc. or Dominion Peoples, Inc. in 2006, 2005, and 2004.

PennTex Illinois, PennTex Resources, Rex III, and Rex IV sold 100.0% of their oil production in the Indiana and Illinois fields to Countrymark Cooperative, LLP. The total amount of oil sold to Countrymark Cooperative, LLP in 2006, 2005, and 2004 was approximately $27.7 million, $18.1 million, and $5.9 million, representing 63.6%, 62.2%, and 41.7%, respectively, of total oil and natural gas sales.

Rex I sold 100.0% of its natural gas production in the Fayette County, Pennsylvania fields to Great Lakes Energy Partners, LLC in 2006 and 2005.

14. 401(K) PLAN

Rex Operating sponsors a 401(k) Plan for its eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Rex Operating contributions to the plan are discretionary. Rex Operating contributions to the plan were $184,782 and $108,800 for the years ended December 31, 2006 and 2005, respectively. Rex Operating paid $8,255 and $4,462 of expenses on behalf of the 401(k) plan for the years ended December 31, 2006 and 2005, respectively.

The W. Douglas Gouge and Company Profit Sharing Plan covered eligible employee of Douglas Oil & Gas. Employees could make contributions to the plan up to allowable limits. Employer contributions to the plan were discretionary. Douglas Oil & Gas contributions to the plan were $46,166 for the year ended December 31, 2004. The W. Douglas Gouge and Company Profit Sharing Plan was terminated in 2005.

15. DISPOSALS AND SALE OF OIL AND GAS PROPERTIES AND OTHER ASSETS

Douglas Oil & Gas

In May 2006, Douglas Oil & Gas sold a parcel of land in New Jersey for $157,066. Douglas Oil & Gas recorded a gain on sale of this undeveloped land of $91,416.

In February 2005, Douglas Oil & Gas sold its remaining interests in the Trenton Black River Project for $550,000. This sale included Douglas Oil & Gas’ interest in the wells and mineral leasehold acreage. Douglas Oil & Gas recorded a loss on sale of these oil and gas properties of $186,983 in 2005.

In November of 2003, the Thomas Ranch well in Grimes County, Texas ceased production due to a collapsed casing. Prior to the collapse, the well was producing approximately 400 Mcf. per day. Douglas Oil & Gas owned a 100.0% interest in the well. In December 2004, Douglas Oil & Gas attempted to restore the well to producing status through a workover that attempted to remove any blockage in the well, which proved unsuccessful. In January 2005, Douglas Oil & Gas attempted a second workover on the well, which was also unsuccessful. Total losses associated with the Thomas Ranch well, including the workover expenses, were $2,103,952. Also during 2004, additional losses of $622,786 were incurred due to the write-off of dry hole drilling expenses. These wells and leases were initially thought to be able to produce in economic quantities, but were later determined to be uneconomical.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

In 2004, Douglas Oil & Gas elected to write-off $297,529 of its costs incurred to obtain 3-D seismic in connection with its Trenton/Black River project. After thorough analysis of the 3-D seismic data, Douglas Oil & Gas did not believe there to be sufficient drilling prospects on Douglas Oil & Gas’ acreage position to continue this project.

The total losses associated with the Thomas Ranch and Trenton/Black River projects were $3,024,267 during 2004 and are included in Combined Statement of Operations.

Midland

In 2004, Midland sold the W. Esperonza Prospect and recognized a $41,667 gain from the sale.

PennTex Resources

In January 2005, PennTex Resources sold its interests in the Black Fork Creek oil and gas field located in Smith County, Texas for $2,971,400. The sale resulted in a gain on disposal of $1,203,528.

In November 2004, PennTex Resources sold its interest in the certain oil and gas properties for $730,000. The transaction resulted in a gain on sale of $628,510.

In February 2004, PennTex Resources sold its interest in the Thomas South oil and gas properties located in Dawson County, Texas for $25,000. The transaction resulted in a loss on sale $10,813.

16. LEASE COMMITENTS

Rex Operating has lease commitments for three different office locations. Lease commitments by year for each of the next five years are as follows at December 31:

2007	$	142,048
2008		117,768
2009		63,264
Thereafter		0
Total	$	323,080

17. INCENTIVE FROM LESSOR

Rex Operating adopted FASB Technical Bulletin 88-1, Issues Relating to Accounting for Leases, to account for a landlord incentive allowance in an operating lease. Rex Operating, as the lessee, entered into an operating lease in which Shaner Brothers, LLC (lessor) offered a $142,344 incentive allowance towards the cost of Rex Operating making leasehold improvements.

In accordance with FASB Technical Bulletin 88-1, Issues Relating to Accounting for Leases, the $142,344 allowance is reported by the lessee as a liability and amortized straight line over the lease term as a reduction of rent expense. The lease term is three years. The total amortization for year ended December 31, 2006 that reduced rent expense is $11,882.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

18. EXPLORATORY WELLS AND PROVED RESERVES

Effective January 1, 2006, New Albany adopted FASB Staff Position No. FAS 19-1; Accounting for Suspended Well Costs. This FASB Staff Position replaces certain paragraphs of FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies (FASB 19) and provided guidance as to whether there are circumstances that would permit the continued capitalization of exploratory well costs beyond one year, other than when additional exploration wells are necessary to justify major capital expenditures and those wells are under way or firmly planned for the near future.

FASB 19 requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs become part of the enterprise’s wells, equipment, and facilities; if, however, the well has not found proved reserves, the capitalized costs of drilling the well are expensed, net of any salvage value. In certain circumstances, an exploratory well finds reserves but those reserves cannot be classified as proved when drilling is completed. To meet the classification of proved reserves, the geological and engineering data must support with reasonable certainty that the quantities of reserves are recoverable under existing economic and operating conditions (typically, prices and costs at the date that the estimate is made).

FASB 19 requires that the cost be carried as an asset provided that (a) there have been sufficient reserves found to justify completion as a producing well if the required capital expenditure is made, and (b) drilling of the additional exploratory wells is under way or firmly planned for the near future. If either of those two criteria is not met, the enterprise must expense the exploratory well costs. The FASB staff believes that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Upon adoption of FASB Staff Position FAS 19-1, New Albany evaluated all existing capitalized exploratory well costs under the provisions of the FASB Staff Position 19-1. As a result, New Albany determined that $2,538,011 of cost was capitalized and is pending determination. New Albany also determined that $35,667 of exploratory costs incurred should be expensed. The following table reflects the net change in capitalized exploratory well costs during 2006:

	2006
Beginning Balance at January 1:	$	0
Capitalized Exploratory Well Costs Charged to Expense Upon Adoption of FAS 19-1		0
Additions of Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves		2,573,678
Reclassification of Wells, Facilities, and Equipment Based on the Determination of Proved Reserves		0
Capitalized Exploratory Well Costs Charged to Expense		(35,667	)
Ending Balance at December 31:	$	2,538,011

The total capitalized exploratory well costs that have been capitalized for a period of one year or less is $2,538,011.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

19. COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION AND DEVELOPMENT ACTIVITIES

Costs incurred by the Company in natural gas and oil property acquisitions and developments are presented below:

	2006		2005
Oil and Natural Gas Property Acquisition Costs	$	69,741,547	$	22,854,640
Undeveloped Acreage		1,116,434		246,203
Unproved Acreage		13,186,186		0
Capitalization of Exploratory Well Costs—Net		2,554,888		0
Development Costs		11,165,936		4,057,855
Total	$	98,164,991	$	27,158,698

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas and oil.

20. OIL AND NATURAL GAS CAPITALIZED COSTS

Aggregate capitalized costs for the Company related to natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization is presented below:

	2006			2005
Proved Oil and Natural Gas Properties	$	127,353,566		$	45,030,383
Pipelines and Support Equipment		2,104,341			1,968,955
Other Field Equipment		587,568			2,254
Field Operation Vehicles		1,448,019			950,031
Wells in Progress		2,861,358			644,903
Unproved Acreage		13,186,186			0
Undeveloped Acreage		197,664			0
Undeveloped Properties		1,185,431			1,261,167
Total		148,924,135			49,857,693
Less Accumulated Depreciation and Depletion		(17,588,964	)		(7,661,541	)
Total	$	131,335,171		$	42,196,152

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

21. RESULTS OF NATURAL GAS AND OIL PRODUCING ACTIVITIES

The results of operations for oil and natural gas and oil producing activities (excluding overhead and interest costs) are presented below:

	2006			2005			2004
Operating Revenue
Oil and Natural Gas Sales	$	43,596,017		$	29,517,590		$	14,158,912
Other Operating Revenue		469,582			270,140			697,412
Realized Gain (Loss) on Hedges		(4,436,347	)		(7,929,478	)		(941,511	)
Unrealized Gain (Loss) on Hedges		5,043,220			(5,541,043	)		(1,395,531	)
Total Operating Revenue	$	44,672,472		$	16,317,209		$	12,519,282
Operating Expenses
Operating Expenses		14,254,594			10,852,439			6,262,259
Production Taxes		551,082			466,223			268,000
Gas Contract Purchases		428,379			402,317			177,515
Impairment Charges on Oil and Gas Properties		0			107,119			3,024,267
Accretion Expense on Asset Retirement Obligation		475,501			199,758			122,008
Depreciation and Depletion		9,771,196			2,966,403			1,858,901
Total Operating Expenses		25,480,752			14,994,259			11,712,950
Results of Operations for Oil and Natural Gas Producing Activities	$	19,191,720		$	1,322,950		$	806,332

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, and other production taxes. In addition, production costs include administrative expenses applicable to support equipment associated with these activities.

Depreciation and depletion expense includes those costs associated with capitalization acquisitions and development costs, but does not include the depreciation applicable to support equipment.

There is no provision for income taxes because the Company is a nontaxable entity.

22. OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED)

The Company’s independent engineers, Netherland, Sewell, and Associates, Inc., have evaluated the Company’s proved oil and natural gas reserves for the year ended December 31, 2006, and have evaluated each of the Founding Companies separately for the year ended December 31, 2005. The Company emphasizes that reserve estimates are inherently imprecise. The Company’s oil and natural gas reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties, and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

Proved oil and natural gas reserves represent the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by natural gas and oil and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil and natural gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2006 and 2005. The reserves are proved.

	2006
	Oil (bls)		Natural Gas (mcf)		Oil Equivalents
Proved Reserves—Beginning of Period	6,378,064		16,094,829		9,060,535
Purchases of Reserves in Place	6,394,302		1,709,829		6,679,273
Extensions, Discoveries, and Other Additions	0		1,184,960		198,253
Revisions of Previous Estimates	(590,959	)	(693,223	)	(707,012	)
Production	(587,385	)	(1,083,538	)	(767,976	)
Proved Reserves—End of Period	11,594,022		17,212,857		14,463,831
	2005
	Oil (bls)		Natural Gas (mcf)		Oil Equivalents
Proved Reserves—Beginning of Period	2,029,996		12,529,937		4,118,319
Purchases of Reserves in Place	3,531,351		5,044,243		4,372,059
Extensions, Discoveries, and Other Additions	0		63,699		10,612
Revisions of Previous Estimates	1,257,675		1,632,511		1,529,614
Sale of Reserves	(50,642	)	(2,070,376	)	(395,705	)
Production	(390,316	)	(1,105,185	)	(574,364	)
Proved Reserves—End of Period	6,378,064		16,094,829		9,060,535
Proved Developed Reserves
December 31, 2005	5,483,425		10,678,872		7,263,237
December 31, 2006	9,294,809		11,366,423		11,189,212

23. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

Statement of Financial Accounting Standard No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proven reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0% annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by SFAS 69 at December 31, 2006 and 2005:

	2006			2005
Future Cash Inflows	$	750,017,452	(a)	$	521,164,297	(b)
Future Production Costs		(362,882,799	)		(202,916,884	)
Future Abandonment Costs		(11,320,089	)		0
Future Development Costs		(34,701,400	)		(20,825,800	)
Net Future Cash Inflows		341,113,164			297,421,613
Less: Effect of a 10.0% Discount Factor		(146,134,451	)		(149,268,713	)
Standardized Measure of Discounted Future
Net Cash Flows	$	194,978,713		$	148,152,900

(a) Calculated using weighted average prices of $5.64 per mcf of natural gas and $57.75 per barrel of oil.

(b) Calculated using weighted average prices of $10.08 per mcf of natural gas and $57.03 per barrel of oil.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

	2006			2005
Standardized Measure—Beginning of Period	$	148,152,900		$	43,707,252
Sales of Product—Net of Production Costs		(25,040,734	)		(16,104,024	)
Purchases of Reserves in Place		105,905,047			49,501,778
Changes in Prices and Production Costs		(45,066,573	)		49,801,537
Changes in Future Development Costs		(2,309,153	)		0
Development Costs Incurred		11,200,333			2,545,830
Plus Extensions, Discoveries, and Other Additions		707,074			245,939
Revisions of Previous Quantity Estimates		(9,105,865	)		24,739,302
Changes in Timing and Other		(1,263,806	)		(4,579,915	)
Future Abandonment Costs		(3,010,780	)		0
Distribution of Reserves on Partnership Redemption		0			(7,088,957	)
Accretion of Discount		14,810,270			5,384,158
Standardized Measure—End of Period	$	194,978,713		$	148,152,900

24. LITIGATION

Douglas Westmoreland—Buckeye Suit

On April 17, 2004, Standard Steel, LLC (“Standard”) filed a complaint in the United States District Court for the Western District of Pennsylvania against Buckeye Energy, Inc. (“Buckeye”) seeking a declaratory judgment declaring the respective rights of Standard and Buckeye relating to three agreements regarding the sale of natural gas from Buckeye’s wells which had been entered into in the early 1980s. The three contracts provide

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YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

for a fixed price to be paid by Standard to Buckeye for natural gas produced from the subject wells. From inception of the contracts and continuing for over 20 years, Standard paid Buckeye (or Buckeye’s predecessors to the contracts) a fixed price for gas which did not vary up or down with the market. In 2001, Buckeye and Standard had entered into amendments to the subject agreement, which added a fixed surcharge to the fixed price paid.

In 2003, Buckeye contended for the first time that the price owed by Standard under the agreements varied with the market price for natural gas. Because the market price for natural gas had risen above the fixed price, Buckeye demanded over $300,000 for gas purchased since 2002 and stated it intended to charge a market price for the future. Standard asked the court to declare that only a fixed price was due for the gas. Buckeye amended its counter-claim to claim over $500,000 for gas sold since 2002 and to seek a declaratory judgment as to future prices. Buckeye also moved for the joinder of Douglas Westmoreland to the action because Standard had conveyed its rights to the gas contracts to the Douglas Westmoreland in March 2004 (See Note 2). Standard did not object to the joinder motion and Douglas Westmoreland was added as a plaintiff in the action.

On January 17, 2005, the parties met in mediation and reached a settlement on the material terms of the dispute. The parties agreed (i) that Standard would pay Buckeye $100,000, (ii) that the price the Douglas Westmoreland would pay Buckeye for natural gas from the wells at issue in the future would be 50.0% of market price received by Douglas Westmoreland when it resold the gas (iii) that a $.10 per Mcf surcharge would be payable by Douglas Westmoreland, (iv) that Douglas Westmoreland would take and pay for up to 100,000 Mcf annually from one of the wells, and (v) that the gas that Buckeye would supply to Douglas Westmoreland would be of a merchantable quantity. The agreement reached at the settlement meeting was not reduced to writing. On January 20, 2005, counsel for the plaintiffs, with the full authorization of Buckeye’s counsel, informed the court that the parties had settled. On January 21, 2005, the court entered an order stating that the case had been settled and that the case would be administratively closed pending the filing of a notice of dismissal. On February 4, 2005, new counsel to Buckeye informed the plaintiff’s counsel that a settlement did not exist and that Buckeye intended to proceed with the litigation. On February 11, 2005, Buckeye filed a motion to reopen the case. On February 25, 2005, Douglas Westmoreland and Standard filed a motion to enforce the oral settlement agreement entered into on January 17, 2005.

On February 25, 2005, Buckeye filed a motion in opposition of enforcement of the settlement contending that it had not entered into a definitive oral settlement agreement at the mediation on January 17, 2005, and in the alternative, in the event the court determined that it had done so, any such agreement was required to be in writing. On July 27, 2005, the court held an evidentiary hearing on the motions. On September 29, 2005, the court issued an order finding that the parties entered into an oral settlement on January 17, 2005. On October 27, 2005, Buckeye appealed the order to the United States Court of Appeals for the Third Circuit.

On December 16, 2005, the parties entered into a written settlement agreement that amended the oral settlement agreement to, among other things, provide that Douglas Westmoreland would pay Buckeye 55.0% of the gross price paid to Douglas Westmoreland when it resells the gas. On January 11, 2006, the Court of Appeals for the Third Circuit dismissed Buckeye’s appeal due to the settlement between the parties, thus resolving the matter. There is no recorded liability related to this matter.

Douglas Westmoreland—Campbell Suit

On November 23, 2004, Dale Campbell (“Campbell”) filed an Amended Complaint in the Court of Common Pleas of Westmoreland County, Pennsylvania against Douglas Westmoreland and Standard, seeking a declaratory judgment that Douglas Westmoreland is required to pay him for natural gas produced at various wells at rates allegedly agreed to under a written agreement and oral agreement between the parties, and account for monies paid to Campbell during the duration of their contractual relationship.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

The well contracts, which are the subject of this lawsuit, were purchased by Douglas Westmoreland in the transaction with Standard. Douglas Westmoreland filed an answer on March 4, 2005, denying the material allegations of Campbell’s compliant and asserting that Campbell’s claims are barred or otherwise fail because, among other reasons, the claims are untimely and because Campbell has already been paid in full. As of December 31, 2006, Campbell had not taken any further action to prosecute the claims asserted in the lawsuit. Douglas Westmoreland believes that Campbell had postponed any further action in the lawsuit pending resolution of the litigation with Buckeye described above. In the event Campbell takes any action in this lawsuit, Douglas Westmoreland intends to vigorously defend the claims that have been asserted against it in this action and to seek a dismissal of the action for failure to prosecute. Douglas Westmoreland believes that the likelihood of an unfavorable outcome of this matter is remote.

PennTex Illinois and Rex Operating—EPA Matter

In September 2006, the United States Department of Justice (“U.S. DOJ”) and the United States Environmental Protection Agency (“U.S. EPA”) initiated an enforcement action against PennTex Illinois and Rex Operating. seeking mandatory injunctive relief and potential civil penalties based on allegations that the companies were violating the Clean Air Act in connection with the release of hydrogen sulfide (H2S) gas and other volatile organic compounds (“VOC’s”) in the course of the companies’ oil operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. The companies’ senior management and representatives of the U.S. EPA, U.S. DOJ, Illinois Environmental Protection Agency (“Illinois EPA”) and the Agency for Toxic Substances and Disease Registry (“ATSDR”) attended a meeting at the offices of the U.S. EPA in Chicago, Illinois on September 7, 2006, to discuss matters relating to the enforcement action. This meeting had been preceded by certain monitoring of air emissions in the areas surrounding Bridgeport, Illinois and Petrolia, Illinois that the U.S. EPA and ATSDR had conducted in May 2006.

As a result of the initial meeting with the government on September 7, 2006, and certain subsequent meetings and communications between the companies’ senior management and the U.S. EPA and U.S. DOJ, PennTex Illinois and Rex Operating executed a non-binding agreement in principle with the U.S. EPA effective October 24, 2006. In the agreement in principle, PennTex Illinois and Rex Operating agreed to develop and carry out a written response plan designed to further reduce possible emissions of H2S and VOC’s from the companies’ oil wells and facilities in the Lawrence Field that are closest to populated areas. The companies agreed to operate and maintain the control measures described in the response plan in accordance with a written operations and maintenance plan to be developed by the companies and approved by the U.S. EPA. The agreement in principle also required PennTex Illinois and Rex Operating to evaluate the effectiveness of the control measures in the Lawrence Field installed pursuant to the response plan through a monitoring program, and required the companies to evaluate the need for additional control measures at other facilities within the Lawrence Field within 60 days. PennTex Illinois and Rex Operating also agreed to present to the U.S. EPA any recommendations for further action the companies might develop based upon their observations of the effectiveness of the control measures. PennTex Illinois and Rex Operating and the U.S. EPA each agreed that they would use their best efforts to negotiate a proposed final settlement agreement that would resolve the government’s enforcement action, which settlement agreement would be published in the Federal Register and made subject to public comment prior to any final approval.

The senior management of PennTex Illinois and Rex Operating and the U.S. EPA and U.S. DOJ are negotiating the terms of a comprehensive consent decree in which PennTex Illinois and Rex Operating, without any admission of wrongdoing or liability and without any agreement to pay any civil fine or penalty, would agree to install certain control measures and to implement certain operating and maintenance procedures regarding the companies’ oil operations in the Lawrence Field. Under the terms of the proposed consent decree, PennTex

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Illinois and Rex Operating would also agree to establish a monitoring protocol that would be designed to facilitate the reduction of possible emissions of H2S and VOC’s from the companies’ operations near Bridgeport, Illinois and Petrolia, Illinois. While at this time the Company is unable to predict with certainty the outcome of this enforcement action and the final terms and conditions of the consent decree, management believes that the companies will be able to reach a final settlement with the government agencies. Management also believes that the consent decree will not require PennTex Illinois and Rex Operating to pay any civil fine or penalty, although it will provide for the possible imposition of specified daily fines and penalties for any days in which it might be determined that the companies have violated the terms and conditions of the consent decree. Any proposed consent decree will ultimately require the approval of a court of proper jurisdiction.

PennTex Illinois and Rex Operating intend to vigorously defend themselves in this matter. In the event that the parties are unable to agree upon the final terms of the consent decree or if the consent decree is not ultimately approved by a court of proper jurisdiction, the Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. See Note 25: Subsequent Events.

PennTex Illinois and Rex Operating—Leib Case

PennTex Illinois and Rex Operating are defendants in a putative class action lawsuit that has been filed in the United States District Court for the Southern District of Illinois, Cause Number 3:06-CV-00802-JPG-CJP, styled “Julia Leib, et al. v. Rex Energy Operating Corp., et al.” This action was commenced on October 17, 2006, by plaintiffs, Julia Leib and Lisa Thompson, individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport, Illinois and Petrolia, Illinois. The complaint asserts that the operation of oil wells that are controlled, owned or operated by PennTex Illinois and Rex Operating. has resulted in “serious contamination” of the class area with H2S. The complaint asserts several causes of action, including violation of the Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct. The complaint seeks, among other things, injunctive relief under the Illinois Environmental Protection Act and Illinois common law, compensatory and other damages, punitive damages, and attorneys’ fees and costs. In addition, the complaint seeks the creation of a court-supervised, defendant-financed fund to pay for medical monitoring for the plaintiffs and others in the class area.

On November 14, 2006, PennTex Illinois and Rex Operating filed a joint answer to the complaint specifically denying virtually all of the allegations in the complaint and asserting affirmative defenses thereto. On December 20, 2006, the plaintiffs filed a motion for class certification requesting that the court certify the case as a class action. PennTex Illinois and Rex Operating intend to vigorously oppose the plaintiffs’ motion for certification of the case as a class action.

Pursuant to the terms of a pollution liability policy with Federal Insurance Company, PennTex Illinois and Rex Operating have insurance coverage for possible damages relating to claims made in this lawsuit for up to $1,000,000. In addition, in accordance with the terms of the pollution liability policy, Federal Insurance Company has agreed to conduct the companies’ defense in this lawsuit at the insurer’s expense. Under the terms of a written agreement with PennTex Illinois and Rex Operating, Federal Insurance Company has agreed to pay a substantial portion of the companies’ costs and expenses relating to the defense of this lawsuit, including attorneys’ fees. Under the terms of the agreement, PennTex Illinois and Rex Operating are required to pay the costs and expenses relating to the defense in excess of the amounts payable by Federal Insurance Company.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

PennTex Illinois and Rex Operating intend to vigorously defend against the claims that have been asserted against the companies in this lawsuit. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or the range of potential loss should the outcome be unfavorable.

PennTex Illinois—ERG v. Tsar Energy II, LLC

At December 31, 2005, PennTex Illinois was involved in a lawsuit with Tsar Energy II, LLC (“Tsar”) and Richard A. Cheatham in the 334th Judicial District Court of Harris County, Texas, cause number 2004-39584, and styled “ERG Illinois, Inc. And Scott Y. Wood v. Tsar Energy II, LLC and Richard M. Cheatham.” The dispute centered around overhead fees charged by PennTex Illinois as operator of jointly-owned oil producing properties located in Illinois and Indiana in which PennTex Illinois owns a 26.0% working interest. Tsar then owned a 49.0% non-operator working interest in the subject properties. PennTex Illinois (then known as ERG Illinois, Inc.) and its former owner, Scott Y. Wood (“Wood”), commenced this litigation in July 2004, by filing a petition against Tsar and its president, Richard M. Cheatham, seeking, among other things, a declaratory judgment that PennTex Illinois, as the operator of the subject properties, was entitled to charge Tsar and the other non-operators their proportionate shares of a fixed monthly overhead charge of $300 for each producing well located within the North Lawrence Unit portion of the properties pursuant to the terms of a operating agreement relating to such unit.

Tsar filed counterclaims against PennTex Illinois (the known as ERG Illinois, Inc.) asserting (i) a breach of contract and declaratory judgment claim seeking an unspecified amount of actual damages along with declaratory relief based on allegations that the Company breached both the joint operating agreement covering the properties in question and a March 2004 letter of intent that preceded it by charging Tsar its proportionate share of a fixed monthly overhead charge of $300 for each producing well located in the North Lawrence Unit portion of the subject properties, (ii) breach of contract claim against the Company seeking $100,000 in actual damages based on Tsar’s allegation that PennTex Illinois breached a verbal agreement between the parties relating to an extension fee, (iii) a claim seeking an unspecified amount of actual and punitive damages based on Tsar’s assertion that PennTex Illinois committed fraud in the inducement in connection with Tsar’s acquisition on March 16, 2004 of its 49.0% non-operating working interest in the subject properties by allegedly making false representations prior to and in the letter of intent executed by PennTex Illinois and Tsar and (iv) a conversion claim seeking actual damages of $100,000 plus an unspecified amount of punitive damages based on Tsar’s allegations that PennTex Illinois improperly converted funds belonging to Tsar.

On December 22, 2005, PennTex Illinois filed motions for summary judgment regarding the principal contract claims at issue and the tort counterclaims that had been asserted against it by Tsar. By order signed February 8, 2006, the court granted the PennTex Illinois’ motion for summary judgment sustaining its right to charge the non-operators of the subject properties their proportionate shares of a fixed monthly overhead charge of $300 for each producing well located within the North Lawrence Unit. By the same order, the court denied PennTex Illinois’ motions for summary judgment seeking dismissal of Tsar’s fraud in the inducement and conversion counterclaims. On March 3, 2006, PennTex Illinois and Tsar jointly moved to sever into a separate action, the claims and counterclaims relating to PennTex Illinois’ charging of fixed monthly overhead on producing wells in the North Lawrence Unit so that the court would be able to sign a final, appealable judgment in PennTex Illinois’ favor on the issues resolved by the court’s summary judgment ruling. The court granted this joint motion on March 3, 2006 and the severed action was docketed in the district court as a severed case styled “ERG Illinois, Inc. v. Tsar Energy II, LLC and Richard M. Cheatham,” bearing cause number 2004-39584-A. On March 31, 2006, Tsar appealed the district court’s final judgment in the severed action to the Court of Appeals First District of Texas.

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NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

On October 3, 2006, Rex Energy IV acquired the 49.0% working interest of Tsar in the Illinois and Indiana properties at issue in the above cases. As part of this transaction, and without payment of any separate consideration, PennTex Illinois obtained a written settlement agreement requiring Tsar and its principal, Richard M. Cheatham, to dismiss with prejudice the claims that they had asserted against PennTex Illinois in both the severed and non-severed actions, and to deliver a mutual release releasing PennTex Illinois and certain other affiliates of PennTex Illinois from any and all liability for claims that had been asserted (or could have been asserted) in the two cases by Tsar and Cheatham. Pursuant to this settlement agreement, the claims asserted against PennTex Illinois in the non-severed action pending in the 334th Judicial District Court of Harris County, Texas, were dismissed with prejudice by an order signed on October 5, 2006. The claims asserted against PennTex Illinois in the severed action were dismissed with prejudice by the Court of Appeals First District of Texas by judgment rendered on October 26, 2006, thereby bringing to a final conclusion not only the appellate case, but the underlying severed district court case from which the appeal had been brought.

PennTex Illinois—Audit Exceptions Claim

On February 1, 2006, PennTex Illinois was served with a draft audit report prepared by an outside auditor retained by Tsar to audit the joint interest billings that were made by PennTex Illinois. The time period of the audit report was March 1, 2004 through June 30, 2005. The audit report purported to identify potential audit exception claims totaling $17,269,956, plus additional unspecified amounts to be determined. However, the audit report identified only $334,180 of audit exception claims that were alleged to be owed to Tsar, and of this amount, $100,000 was attributable to an extension fee dispute which was the subject of two of Tsar’s counterclaims in the ERG vs. Tsar litigation discussed above. In addition, $2,510,853 of the gross amount of the audit exceptions claims described in the audit report was attributable to the fixed monthly overhead charges of $300 per producing well in the North Lawrence Unit portion of the jointly owned properties that was upheld as a matter of law by the court’s summary judgment ruling rendered February 8, 2006 in the ERG vs. Tsar litigation described above.

On February 3, 2006, Tsar filed a formal nonsuit without prejudice to its breach of contract counterclaim asserted against PennTex Illinois in the ERG vs. Tsar case that had sought to recover damages if an accounting of the charges to the joint account revealed that they were inaccurate. On July 31, 2006, PennTex Illinois submitted to Tsar its written response to Tsar’s audit report. PennTex Illinois’ response stated that the majority of the audit exceptions set forth in the audit report were unsupported, not evidenced by true audit work, based on supposition and hearsay, and not presented in the manner required by applicable guidance of the Council of Petroleum Accounting Societies (“COPAS”). The majority of the audit exceptions set forth in the report were denied by PennTex Illinois; however, PennTex Illinois identified costs and expenses totaling $106,616 which were owed to PennTex Illinois by Tsar.

In connection with the settlement of the Tsar lawsuit (See ERG v. Tsar Energy II, LLC above), PennTex Illinois, without payment of any separate consideration, obtained a full and complete release of the audit exception claims asserted by Tsar in its audit report dated February 1, 2006. This release, which was executed by Tsar on October 3, 2006, was obtained pursuant to the acquisition transaction pursuant to which Rex Energy IV acquired the working interest of Tsar in the jointly-owned oil producing properties located in Illinois and Indiana.

PennTex Resources

PennTex Resources is involved in an arbitration panel convened by the American Arbitration Association in Houston, Texas, Cause Number 70 180 Y 00437 06, styled “PennTex Resources, L.P. And Lance T. Shaner, Claimants v. ERG Illinois Holdings, Inc. And Scott Y. Wood, Respondents.” This is a binding arbitration

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YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

proceeding that was commenced on June 21, 2006, by PennTex Resources and Lance T. Shaner (“Shaner”) against ERG Illinois Holdings, Inc. (“ERG Holdings”) and Scott Y. Wood (“Wood”) pursuant to the dispute resolution provisions of a stock purchase agreement that was entered into in January 2005 by Wood’s company, ERG Holdings, as “Seller” and PennTex Resources, as “Buyer” (the “2005 Stock Purchase Agreement”).

The principal claim in the arbitration proceeding is PennTex Resources and Shaner’s claim that ERG Holdings and Wood should be ordered to comply with a “release obligation” contained in the 2005 Stock Purchase Agreement that requires Wood, under certain designated circumstances, to dismiss or release the individual claims that he is prosecuting against Tsar Energy II, LLC (“Tsar”) and Richard M. Cheatham (“Cheatham”) in a lawsuit in the 334th Judicial District Court of Harris County, Texas, cause number 2004-39584, styled “ERG Illinois, Inc. And Scott Y. Wood v. Tsar Energy II, LLC And Richard M. Cheatham (the “Tsar Case”). The dispute in the Tsar Case centers around overhead fees charged by PennTex Illinois as operator of jointly-owned oil producing properties located in Illinois and Indiana in which PennTex Resources owns a 25.0% working interest (the “Illinois and Indiana Properties”). Tsar then owned a 49.0% non-operator working interest in the subject properties. PennTex Illinois (then known as ERG Illinois, Inc.) and its former owner, Wood, commenced this litigation in July 2004, by filing a petition against Tsar and its president, Cheatham, seeking, among other things, a declaratory judgment that PennTex Illinois, as the operator of the subject properties, was entitled to charge Tsar and the other non-operators their proportionate shares of a fixed monthly overhead charge of $300 for each producing well located within the North Lawrence Unit portion of the properties pursuant to the terms of a operating agreement relating to such unit. PennTex Resources became obligated to file this arbitration proceeding seeking to enforce Wood’s “release obligation” under the 2005 Stock Purchase Agreement, and to prosecute such proceeding diligently without compromise until final award, by reason of an agreement that PennTex Illinois and PennTex Resources entered into on March 2, 2006 with Tsar and Cheatham in order to resolve certain procedural issues relating to the Tsar Case.

PennTex Resources and/or Shaner have also filed the following additional claims in the arbitration proceeding in which PennTex Resources or Shaner seek an award of money damages from ERG Holdings: (a) Shaner, as the assignee of the “Buyer” under the 2005 Stock Purchase Agreement, has filed a claim against ERG Holdings, as the “Seller” under the 2005 Stock Purchase Agreement, seeking an award of $383,760, plus pre-award interest and attorneys’ fees, based on ERG Holdings’ alleged breach of its obligation to make an appropriate post-closing purchase price adjustment as required under the terms of Section 2.2(c)(D) of the 2005 Stock Purchase Agreement; (b) PennTex Resources has filed a claim against ERG Holdings seeking an award of approximately $20,000, plus pre-award interest and attorneys’ fees, based on ERG Holdings’ alleged breach of a contractual obligation, allegedly arising under Section 9.4(d) of the 2005 Stock Purchase Agreement, to return the original and all copies of a letter a credit posted by the Buyer under that agreement to secure its indemnity obligations described in Section 9.4, which breach is alleged to have wrongfully caused PennTex Resources to have had to unnecessarily incur an annual renewal fee to keep such letter of credit in force so as to prevent ERG Holdings from having the right to draw on it (PennTex Resources’ claim in this regard also seeks equitable and injunctive relief that would declare the letter of credit void and restrain ERG Holdings from attempting to draw on it.); and (c) PennTex Resources has filed a claim against ERG Holdings seeking an award of approximately $23,500 (which PennTex Resources believes is likely to be revised downward to approximately $2,500), plus pre-award interest and attorneys’ fees, based on ERG Holdings’ alleged breach of its obligation to make an appropriate pre-closing purchase price adjustment as required under the terms of Section 2.2(c)(C) of the 2005 Stock Purchase Agreement by failing to reflect in its final closing statement an existing liability owed to the owners of a net profits interest relating to certain leases within the Illinois and Indiana Properties.

In its pleading filed on January 22, 2007, ERG Holding and Wood have denied all of the PennTex Resources’ and Shaner’s claims, and ERG Holdings has asserted a counterclaim against PennTex Resources

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YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

based on its previously-asserted claim that it is entitled to a post-closing adjustment in the purchase price in its favor in the amount of $182,864.97. The arbitration panel of the American Arbitration Association has scheduled a final hearing in the arbitration proceeding for June 25-26, 2007.

PennTex Resources and Shaner intend to vigorously prosecute all of the claims asserted in the arbitration proceedings, including Shaner’s claim seeking a final purchase price closing adjustment in the amount of $383,760 in favor of Shaner as the assignee of the “Buyer” under the 2005 Stock Purchase Agreement. PennTex Resources and Shaner will also vigorously defend ERG Holdings’ counterclaim seeking an award that would result in a final purchase price closing adjustment in the amount of $182,865 in favor of the “Seller” under the 2005 Stock Purchase Agreement. PennTex Resources is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter. However, given that it is extremely unlikely that the arbitration panel would allow either party to amend their respective final purchase price adjustment claims to increase the amounts sought therein, PennTex Resources believes that the amount of potential loss to the Company should the outcome be unfavorable would be no more than $182,865, plus pre-award interest on such sum.

PennTex Resources was involved in a civil lawsuit in United States District Court for the Southern District of Texas, Houston Division, Civil Action Number H-06-2198, styled “Scott Y. Wood v. PennTex Resources, L.P. And Lance T. Shaner.” This action was commenced on June 30, 2006, by Wood in an effort to obtain a declaratory judgment that he cannot be compelled to participate in the arbitration proceeding that PennTex Resources and Shaner had commenced on June 21, 2006, against ERG Holdings and Wood as described above. Wood is not a designated signatory party to the 2005 Stock Purchase Agreement described above, but is explicitly named as a beneficiary of a comprehensive set of indemnity provisions in that agreement that provided Wood and others with protection from liability in the Tsar Case. On August 1, 2006, PennTex Resources and Shaner responded to Wood’s complaint by filing an answer and counterclaim asserting that the action should be stayed, and that Wood should be compelled to proceed to arbitration in the pending arbitration proceeding notwithstanding that he was not a designated signatory party to the 2005 Stock Purchase Agreement that contains both the “release obligation” at issue and the dispute resolution provisions creating rights to seek binding arbitration with respect to issues relating to that Agreement. On October 23, 2006, the court issued a Memorandum And Order granting PennTex Resources’ and Shaner’s motion to compel arbitration. On November 2, 2006, in response to defendants’ joint motion in support of stay, rather than dismissal, the court signed an order staying the action and administratively closing it pending the final award in the underlying arbitration proceeding.

This action does not involve a claim against PennTex Resources for damages or any other form of monetary relief. PennTex Resources and Shaner vigorously defended this action, and used it as a procedural vehicle to compel Wood to participate in the pending arbitration proceeding described above. PennTex Resources does not believe that this action as presently constituted can result in any loss to PennTex Resources.

25. SUBSEQUENT EVENTS

New Albany

Through February 2007, New Albany issued two mandatory capital calls to its members totaling $2,120,073. The Founding Companies’ portion of these capital calls was $470,650.

On January 26, 2007, New Albany acquired a 45.0% working interest in 2,171 gross acres located in Knox County, Indiana from Source Rock Resources, Inc. for $44,511.

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YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

On March 12, 2007, New Albany entered into an Extension Agreement with its 50.0% member, Baseline Oil & Gas Corp. (“Baseline”). Under the terms of the Extension Agreement, Baseline was granted a one week extension to March 16, 2007 to pay a mandatory capital call issued by New Albany to Baseline in the amount of $492,424. In addition, the Extension Agreement provided that in the event Baseline paid New Albany an additional $1,729,033 in outstanding capital calls by March 16, 2007, New Albany would redeem Baseline’s 50.0% membership interest in New Albany pursuant to the terms of a mutually agreed upon redemption agreement. Under the terms of the form of redemption agreement, New Albany would agree that in exchange for the redemption of Baseline’s 50.0% membership interest in New Albany, New Albany would assign 50.0% of its assets, including its leasehold mineral interests, to Baseline. The Extension Agreement provided that in the event that Baseline failed to pay all outstanding capital calls by March 16, 2007, New Albany, and its non-defaulting members, would be entitled to exercise the rights set forth in Section 3.3(a) of New Albany’s limited liability company agreement dated November 25, 2005. Section 3.3(a) provides that in the event a member fails to pay certain mandatory capital calls issued by the managing member of New Albany, New Albany may permit other non-defaulting members to contribute the amount owed by the defaulting member as an additional capital contribution to New Albany. In such event, the membership interests of all members of New Albany will be adjusted pursuant to a formula, the numerator of which is the member’s total capital contributions to New Albany, and the denominator of which is the sum of all members’ total capital contributions to New Albany. The Extension Agreement further provided that in the event that Baseline’s membership interest in New Albany was reduced in the manner set forth above due to its failure to pay all of the outstanding capital calls, New Albany, under the terms of the Redemption Agreement, must immediately thereafter redeem Baseline’s interest in New Albany in exchange for the assignment to Baseline of an interest in all of New Albany’s assets equal to Baseline’s then reduced membership interest.

On March 16, 2007, Baseline paid to New Albany $300,000 of the outstanding capital calls owed to New Albany, leaving an unpaid capital call balance of $1,921,457. Immediately thereafter, in accordance with the terms of the Extension Agreement and Section 3.3.(a) of New Albany’s limited liability company agreement, Baseline’s membership interest in New Albany was reduced from 50.0% to 40.42%. Baseline and New Albany then entered into a redemption agreement providing that Baseline’s membership interest in New Albany was redeemed in exchange for an assignment by New Albany to Baseline of a 40.42% interest in all of New Albany’s assets, including its oil and gas leasehold interests. On March 16, 2007, pursuant to Section 3.3(a) of New Albany’s limited liability company agreement, Rex II elected to pay $3,156,600 to New Albany in satisfaction of its outstanding capital calls, as well as the unpaid outstanding capital calls of Baseline, Rex Energy Wabash, LLC, Shaner & Hulburt Capital Partners Limited Partnership and Lance T. Shaner. In accordance with Section 3.3(a) of New Albany’s limited liability company agreement, the membership interests of the members were thereafter adjusted to reflect the additional capital contributions made by Rex II on behalf of Baseline, Rex Energy Wabash, LLC, Shaner & Hulburt Capital Partners Limited Partnership and Lance T. Shaner, and the redemption of Baseline’s 40.42% membership interest. Following such adjustments, Rex II’s membership interest in New Albany was increased from 26.833% to 45.04%, Rex Energy Wabash, LLC’s membership interest was increased from 0.78% to 1.31%, Lance T. Shaner’s membership interest was increased from 17.93% to 30.09%, Shaner & Hulburt Capital Partners Limited Partner’s membership interest was increased from 2.94% to 4.93% and Douglas Oil & Gas’s membership interest was increased from 11.10% to 18.63%.

PennTex Illinois and Rex Operating

On January 26, 2007, the United States District Court for the Southern District of Illinois, in the case of the putative class action lawsuit filed against PennTex Illinois and Rex Energy Operating (See Note 25: Litigation), issued a scheduling and discovery order establishing deadlines for completing discovery and briefing relating to the plaintiffs’ motion for class certification. The order states that after the filing of the last brief on class

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YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

certification issues on August 31, 2007, the court will schedule a hearing on plaintiffs’ motion for class certification. PennTex Illinois and Rex Operating intend to vigorously oppose the plaintiffs’ motion for certification of the case as a class action. On January 31, 2007, the plaintiffs in the above action filed a motion for leave seeking permission to file an amended complaint that would add a claim against the defendants for alleged violation of Section 7002(a)(1) of the Resource Conservation And Recovery Act (“RCRA”). Plaintiffs’ proposed amended complaint makes factual allegations similar to those previously asserted in Plaintiffs’ prior pleadings. The Company believes that it is likely that the court will grant Plaintiffs’ leave to file the amended complaint. On February 6, 2007, the court set a final pretrial conference for this case for August 7, 2008. The case is scheduled for jury trial on August 18, 2008, in the United States District Court for the Southern District of Illinois located in Benton, Illinois. The parties to this lawsuit have exchanged initial pretrial disclosures as required under the applicable rules and each side has served and responded to pre-deposition written discovery. PennTex Illinois and Rex Operating intend to vigorously defend against the claims that have been asserted against them in this lawsuit. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or the range of potential loss should the outcome be unfavorable to PennTex Illinois and Rex Operating.

In September 2006, the U.S. DOJ and the U.S. EPA initiated an enforcement action seeking mandatory injunctive relief and potential civil penalties from PennTex Illinois and Rex Operating based on allegations that the companies were violating the Clean Air Act in connection with the release of H2S and other volatile organic compounds, or VOCs, in the course of PennTex Illinois’ oil operations in the Lawrence Field near the towns of Bridgeport and Petrolia, Illinois. In April 2007, PennTex Illinois, Rex Operating and the U.S. EPA and U.S. DOJ executed a comprehensive consent decree in which PennTex Illinois and Rex Operating, without any admission of wrongdoing or liability and without any agreement to pay any civil fine or penalty, agreed to install certain control measures and to implement certain operating and maintenance procedures in the Lawrence Field.

PennTex Illinois and Rex Energy Operating estimate the incremental costs that will be incurred in order to comply with the provisions of the consent decree will be approximately $1.4 million, all of which will be incurred in 2007.

Under the terms of the consent decree, PennTex Illinois and Rex Operating agreed to establish a monitoring protocol that would be designed to facilitate the reduction of possible emissions of H2S and VOCs from PennTex Illinois’ operations near Bridgeport and Petrolia. The consent decree is currently under judicial review and a public comment period. While at this time we are unable to predict with certainty the outcome of the enforcement action and the final terms and conditions of the consent decree, we believe that the executed consent decree will ultimately be approved by the court of proper jurisdiction, thereby resolving the enforcement action according to the terms described in the executed consent decree. The executed consent decree does not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any days in which it might be determined that the we have violated the terms and conditions of the consent decree.

PennTex Resources

On February 28, 2007, PennTex Resources received a letter from counsel to ERG Holdings and Wood demanding that PennTex Resources and Lance T. Shaner reimburse ERG Holdings and Wood for legal fees alleged to be incurred by the parties in connection with the Tsar Case in the amount of $171,351 (See Note 24). ERG Holdings and Wood contend that the 2005 Stock Purchase Agreement requires PennTex Resources and Lance T. Shaner to reimburse them for all legal costs and expenses relating to the Tsar Case. PennTex Resources and Lance T. Shaner contend that the 2005 Stock Purchase Agreement requires that PennTex Resources

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YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

reimburse ERG Holdings and Wood for legal costs incurred in their defense of the Tsar Case, but that PennTex Resources is not required to pay any legal costs incurred by ERG Holdings and Wood in connection with the prosecution of Wood’s claims against Tsar, and that this arrangement for the payment of legal fees was previously orally agreed to by ERG Holdings and Wood. In the letter dated February 28, 2007, ERG Holdings and Wood stated that it in event that PennTex Resources and Lance T. Shaner refuse to pay the claimed legal fees, ERG Holdings and Wood will add an additional counterclaim to the arbitration proceeding currently pending before the American Arbitration Association in Houston, Texas described in Note 24. On March 15, 2007, PennTex Resources paid $15,021 to ERG Holdings and Wood for legal costs incurred in their defense of the Tsar Case in January 2006. PennTex Resources believes that ERG Holdings and Wood are not entitled to any further reimbursement of legal costs incurred in their defense of the Tsar Case.

PennTex Resources and Lance T. Shaner intend to vigorously oppose any attempts by ERG Holdings and Wood to add a counterclaim to the arbitration proceeding on the grounds that the panel imposed deadline for adding counterclaims has passed. In the event that the arbitration panel permits ERG Holdings and Wood to add the counterclaim, PennTex Resources and Lance T. Shaner intend to vigorously defend themselves against the counterclaim. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter. The Company believes that the amount of potential loss to PennTex Resources should the outcome of the counterclaim be unfavorable would be no more than $156,330, plus pre-award interest on such sum.

Rex II

On February 13, 2007, Rex II entered into an Amended and Restated Credit Agreement dated as of February 13, 2007 with Sovereign Bank, as Administrative Agent and Lead Arranger on behalf of signatory lenders which are parties to the agreement from time to time. At the closing of this loan transaction, the outstanding balance under Rex II’s revolving line of credit with Sovereign Bank of $3,592,027 was refinanced and became an outstanding obligation under the new credit facility. The new credit facility provides for loans and letters of credit of up to a maximum of $10,000,000. Under the new credit facility, Rex II may borrow funds under an alternative base rate or Eurodollar rate. Under the alternative base rate, Rex II may borrow funds at a rate per annum equal to the greater of (i) the prime rate in effect on such day (which is defined as the rate of interest per annum publicly announced from time to time by Sovereign Bank as its prime rate in effect at its principal office) and (ii) the Federal Funds Effective Rate (which is defined as the weighted average of the rates on overnight Federal fund transactions with members of the Federal Reserve System) in effect on such day plus  ¹/2 of 1%. Under the Eurodollar rate, Rex II may borrow funds a rate per annum equal to the LIBO rate for such period multiplied by the statutory reserve rate. The statutory reserve rate is calculated as a fraction, the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the applicable maximum reserve percentages expressed as a decimal established by the Federal Reserve Board for eurocurrency funding. Borrowings under the new credit facility mature on March 24, 2008. Provided that certain conditions under the credit agreement are met, Rex II may at any time and from time to time repay outstanding borrowings under the new credit facility, in whole or in part, without premium or penalty.

Borrowings under the new credit facility are secured by all of Rex II’s oil and gas assets located in the states of Illinois and Indiana. In the event that all outstanding borrowings under the credit facility are not repaid by September 30, 2007 or a borrowing base deficiency under the terms of the credit facility otherwise occurs, the lenders may require Rex II to grant additional security interests in other oil and gas properties of the Company. The Amended and Restated Credit Agreement requires Rex II to meet certain financial covenants and ratios including minimum current assets to liabilities ratio, minimum debt service coverage ratio and minimum interest coverage ratio. In addition, Rex II must meet certain requirements regarding quarterly and annual financial

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YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

reporting and semi-annual oil and gas reserve reporting. The Amended and Restated Credit Agreement also contains non-financial covenants, which restrict the action of Rex II with respect to the incurrence of additional indebtedness, sale of Rex II’s assets, the making of investments, transactions with affiliated companies, and the creation of additional liens on the assets of Rex II.

Subsequent to December 31, 2006, Rex II borrowed an additional $3,141,878 under the new credit facility. As of February 28, 2007, outstanding borrowings under the new credit facility were $6,692,027. Borrowings under the new credit facility were used to fund Rex II’s acquisition of additional oil and gas properties, development costs associated with Rex II’s existing oil and gas properties and for general purposes of the Company.

On February 26, 2007, Rex II acquired a 90.0% working interest in 6 oil and gas leases covering properties located in Hardin County, Texas for $1,080,000. The acquisition included interests in 3 producing oil wells and related infrastructure and equipment. The interests were purchased from the Creditor’s Trust for Central Utilities Production Corp., a creditor’s trust established in connection with a bankruptcy case styled In re Central Utilities Production Corp., Case No. 03-44067, filed in the United States Bankruptcy Court, Eastern District of Texas, Sherman Division. The effective date of the acquisition was February 1, 2007.

On April 19, 2007, Rex II acquired a 52.375%, and 83.707%working interest in 2 oil and gas leases covering properties located in Concho County, Texas for $890,000. The acquisition included interests in 13 producing oil wells and related infrastructure and equipment. The interests were purchased from various working interest owners, including Ultra Oil & Gas Inc. Ultra Oil & Gas Inc. acted as agent for the various sellers. The effective date of the acquisition was January 1, 2007.

Debt Covenants

As of December 31, 2006, PennTex Illinois and PennTex Resources, as co-borrowers, were not in compliance with the negative covenant in their credit agreement requiring that their ratio of current assets to current liabilities, as defined in the credit agreement, be at lease 1.1:1. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarters of 2007.

As of December 31, 2006, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, were not in compliance with the negative covenant in the credit agreement for the M&T Loan which states that the co-borrowers will not permit their tangible net worth, on a combined basis, as of the end of any fiscal year to be less than such amount that is 15% less than the tangible net worth of the co-borrowers as indicated on their audited year end financial statements as of December 31, 2005; provided, however, that commencing on December 31, 2006, and at the end of each fiscal year thereafter, this amount will increase by $500,000. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarters of 2007.

As of December 31, 2006, Rex III was not in compliance with the negative covenant contained in its credit agreement requiring that its ratio of total reserve value to total funded debt, as defined in the credit agreement, be at least 2.5:1. Rex III obtained a written waiver from its lenders regarding its non-compliance with this negative covenant for the fourth quarter of 2006 and the first and second quarter of 2007.

As of December 31, 2006, Rex IV was not in compliance with the negative covenant in its credit agreement requiring that its ratio of total debt to EBITDAX, as defined in the credit agreement, shall not exceed 5.5:1. On March 9, 2007, Rex IV obtained a written waiver from KeyBank of this covenant for the fourth quarter of 2006.

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YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

As of December 31, 2006, Rex IV was not in compliance with the negative covenant in its credit agreement with KeyBank requiring that its ratio of total debt to EBITDAX, as defined above, shall not exceed 5.5:1. On March 9, 2007, Rex IV obtained a written waiver from KeyBank of this covenant for the fourth quarter of 2006. On March 30, 2007, Rex IV and KeyBank executed a First Amendment to the Credit Agreement which extended the maturity date of borrowings under the credit agreement to the earlier of (i) the date of closing of the Company’s initial public offering or (ii) December 31, 2007. In addition, the First Amendment provided for a change in the interest rate per annum for Eurodollar borrowings to the LIBO rate plus 400 basis points. The First Amendment to the Credit Agreement also provided for revisions to certain negative covenants contained in the credit agreement. The ratio of total debt to EBITDAX was changed from 5.75:1.00 to 7.00:1.00 for the fiscal quarter ending June 30, 2007, 6.75:1.00 for the fiscal quarter ending September 30, 2007 and 6.50:1.00 for the fiscal quarter ending December 31, 2007. The First Amendment also provided that for the purposes of calculating both ratios, EBITDAX excludes non-reoccurring legal expenses of Rex IV.

26. COMBINED FINANCIAL STATEMENTS

As described in Note 1, the combined financial statements include the 13 entities that comprise the Founding Companies of Rex Energy Corporation. The following information presents combining financial statements, which include the individual company information and the eliminations necessary to combine the Founding Companies of Rex Energy Corporation.

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YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING BALANCE SHEET

December 31, 2006

	PennTex Resources Illinois, Inc.			PennTex Resources, LP			Rex Energy Royalties, LP			Douglas Oil & Gas, LP			Douglas Westmoreland, LP			Midland Exploration, LP
ASSETS
Current Assets
Cash and Cash Equivalents	$	6,951		$	27,805		$	1,482		$	0		$	0		$	64,245
Restricted Cash		0			0			0			0			0			0
Accounts Receivable		2,497,182			1,195,004			66,315			1,518,773			672,686			80,231
Short-Term Derivative Instruments		0			0			0			401,367			401,367			0
Inventory, Prepaid Expenses and Other		606,744			87,466			0			95,867			0			2,088
Total Current Assets		3,110,877			1,310,275			67,797			2,016,007			1,074,053			146,564
Property and Equipment
Evaluated Oil and Gas Properties		8,614,317			5,612,267			1,500,000			13,235,006			5,796,901			692,637
Unevaluated Oil and Gas Properties		0			0			0			140,443			0			0
Other Property and Equipment		578,855			0			0			680,962			40,104			0
Wells in Progress		80,000			0			0			189,293			0			0
Pipelines		0			0			0			1,530,969			233,470			0
Total Property and Equipment		9,273,172			5,612,267			1,500,000			15,776,673			6,070,475			692,637
Less: Accumulated Depreciation, Depletion and Amortization		(1,652,006	)		(1,532,518	)		(258,162	)		(6,520,122	)		(1,024,040	)		(372,565	)
Net Property and Equipment		7,621,166			4,079,749			1,241,838			9,256,551			5,046,435			320,072
Other Assets
Other Assets—Net		0			235,549			0			1,444,755			0			0
Long-Term Derivative Instruments		22,746			0			0			0			0			0
Total Other Assets		22,746			235,549			0			1,444,755			0			0
Total Assets	$	10,754,789		$	5,625,573		$	1,309,635		$	12,717,313		$	6,120,488		$	466,636
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable and Accrued Expenses	$	2,391,343		$	777,858		$	0		$	407,197		$	426,193		$	106,728
Short-Term Derivative Instruments		2,098,391			873,909			0			0			0			0
Accrued Distributions		0			0			0			0			0			102,465
Lines of Credit		0			0			0			0			0			0
Current Portion of Long-Term Debt		90,330			0			0			21,656			5,036			0
Related Party Payable		1,820,000			1,291,201			0			35,705			530,467			43,827
Total Current Liabilities		6,400,064			2,942,968			0			464,558			961,696			253,020
Long-Term Liabilities
Long-Term Debt		2,300,000			12,644,536			0			5,941,586			3,000,000			0
Other Loans and Notes Payable—Long-Term Portion		148,922			0			0			74,765			14,796			0
Long-Term Derivative Instruments		0			132,668			0			99,733			99,733			0
Participation Liability—Net		0			0			0			0			2,141,109			0
Other Liabilities		0			0			0			322,046			0			0
Asset Retirement Obligation		920,568			887,569			0			229,677			132,485			8,375
Total Long-Term Liabilities		3,369,490			13,664,773			0			6,667,807			5,388,123			8,375
Total Liabilities		9,769,554			16,607,741			0			7,132,365			6,349,819			261,395
Minority Interests		0			0			1,252,449			4,381,617			(281,140	)		196,311
Owners’ Equity
Common Stock		1,000			0			0			0			0			0
Additional Paid-In Capital		1,460,000			0			0			0			0			0
Accumulated Stockholders’ (Deficit)		(475,765	)		0			0			0			0			0
Partners’ and Members’ Equity (Deficit)		0			(10,982,168	)		57,186			1,203,331			51,809			8,930
Total Owners’ Equity (Deficit)		985,235			(10,982,168	)		57,186			1,203,331			51,809			8,930
Total Liabilities, Minority Interests and Owners’ Equity (Deficit)	$	10,754,789		$	5,625,573		$	1,309,635		$	12,717,313		$	6,120,488		$	466,636

F-110

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING BALANCE SHEET

December 31, 2006

	Rex Energy, LP			Rex Energy II, LP			Rex Energy II Alpha, LP			Rex Energy III, LLC			Rex Energy IV, LLC			New Albany- Indiana, LLC		Rex Energy Operating Corp.			Eliminations			Total
ASSETS
Current Assets
Cash and Cash Equivalents	$	71,467		$	57,164		$	2,606		$	0		$	239,683		$	101,903	$	26,490		$	0		$	599,796
Restricted Cash		0			0			0			0			0			0		0			0			0
Accounts Receivable		17,532			1,241,945			43,251			622,891			1,622,026			94,375		236,982			(3,023,260	)		6,885,933
Short-Term Derivative Instruments		0			0			0			456,498			15,633			0		0			0			1,274,865
Inventory, Prepaid Expenses and Other		0			110,102			1,025			378,554			174,887			0		63,519			0			1,520,252
Total Current Assets		88,999			1,409,211			46,882			1,457,943			2,052,229			196,278		326,991			(3,023,260	)		10,280,846
Property and Equipment
Evaluated Oil and Gas Properties		186,751			28,928,079			1,207,102			24,166,475			37,430,910			0		0			0			127,370,445
Unevaluated Oil and Gas Properties		0			1,043,036			1,952			197,664			0			13,186,186		0			0			14,569,281
Other Property and Equipment		0			9,256			0			1,163,000			0			578,312		1,131,354			0			4,181,843
Wells in Progress		0			20,300			0			0			0			2,554,888		0			0			2,844,481
Pipelines		0			0			0			0			0			0		0			0			1,764,439
Total Property and Equipment		186,751			30,000,671			1,209,054			25,527,139			37,430,910			16,319,386		1,131,354			0			150,730,489
Less: Accumulated Depreciation, Depletion and Amortization		(37,333	)		(3,042,174	)		(159,900	)		(1,933,620	)		(1,064,648	)		0		(117,545	)		0			(17,714,633	)
Net Property and Equipment		149,418			26,958,497			1,049,154			23,593,519			36,366,262			16,319,386		1,013,809			0			133,015,856
Other Assets
Other Assets—Net		2,395,963			1,714,297			0			385,746			326,413			0		46,747			(5,377,675	)		1,171,795
Long-Term Derivative Instruments		0			0			0			120,109			0			0		0			0			142,855
Total Other Assets		2,395,963			1,714,297			0			505,855			326,413			0		46,747			(5,377,675	)		1,314,650
Total Assets	$	2,634,380		$	30,082,005		$	1,096,036		$	25,557,317		$	38,744,904		$	16,515,664	$	1,387,547		$	(8,400,935	)	$	144,611,352
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable and Accrued Expenses	$	0		$	1,020,373		$	402		$	789,541		$	854,115		$	1,050,788	$	511,042		$	0		$	8,335,580
Short-Term Derivative Instruments		0			5,397			0			0			0			0		0			0			2,977,697
Accrued Distributions		0			0			0			0			0			0		0			0			102,465
Lines of Credit		0			0			0			0			37,580,634			0		0			0			37,580,634
Current Portion of Long-Term Debt		0			0			0			2,475,000			0			0		275,518			0			2,867,540
Related Party Payable		0			173,246			1,944			484,658			8,877			3,683		449,652			(3,023,260	)		1,820,000
Total Current Liabilities		0			1,199,016			2,346			3,749,199			38,443,626			1,054,471		1,236,212			(3,023,260	)		53,683,916
Long-Term Liabilities
Long-Term Debt		0			3,550,149			0			17,525,000			0			0		0			0			44,961,271
Other Loans and Notes Payable—Long-Term Portion		0			0			0			0			0			0		242,890			0			481,373
Long-Term Derivative Instruments		0			134,168			10,923			0			1,220,900			0		0			0			1,698,125
Participation Liability—Net		0			0			0			0			0			0		0			0			2,141,109
Other Liabilities		0			0			0			0			0			0		83,034			0			405,080
Asset Retirement Obligation		0			762,893			38,131			652,331			1,619,576			16,877		0			0			5,268,482
Total Long-Term Liabilities		0			4,447,210			49,054			18,177,331			2,840,476			16,877		325,924			0			54,955,440
Total Liabilities		0			5,646,226			51,400			21,926,530			41,284,102			1,071,348		1,562,136			(3,023,260	)		108,639,356
Minority Interests		2,047,180			21,663,512			1,044,636			337,471			(1,269,599	)		11,498,791		(69,836	)		(4,212,032	)		36,589,360
Owners’ Equity
Common Stock		0			0			0			0			0			0		60			0			1,060
Additional Paid-In Capital		0			0			0			0			0			0		0			0			1,460,000
Accumulated Stockholders’ (Deficit)		0			0			0			0			0			0		(104,813	)		0			(580,578	)
Partners’ and Members’ Equity (Deficit)		587,200			2,772,267			0			3,293,316			(1,269,599	)		3,945,525		0			(1,165,643	)		(1,497,846	)
Total Owners’ Equity (Deficit)		587,200			2,772,267			0			3,293,316			(1,269,599	)		3,945,525		(104,753	)		(1,165,643	)		(617,364	)
Total Liabilities, Minority Interests and Owners’ Equity (Deficit)	$	2,634,380		$	30,082,005		$	1,096,036		$	25,557,317		$	38,744,904		$	16,515,664	$	1,387,547		$	(8,400,935	)	$	144,611,352

F-111

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING BALANCE SHEET

December 31, 2005

	PennTex Resources Illinois, Inc.			PennTex Resources, LP			Rex Energy Royalties, LP			Douglas Oil & Gas, LP			Douglas Westmoreland, LP
ASSETS
Current Assets
Cash and Cash Equivalents	$	0		$	0		$	711		$	606,373		$	210,242
Restricted Cash		0			500,000			0			0			0
Accounts Receivable		1,902,021			1,076,844			417,417			1,573,878			493,073
Short-Term Derivative Instruments		0			0			0			0			0
Inventory, Prepaid Expenses and Other		406,694			114,609			0			27,954			7,403
Total Current Assets		2,308,715			1,691,453			418,128			2,208,205			710,718
Property and Equipment
Evaluated Oil and Gas Properties		7,301,705			4,370,549			1,500,000			11,262,655			4,430,617
Unevaluated Oil and Gas Properties		0			0			0			1,013,645			0
Other Property and Equipment		568,867			0			0			687,307			40,104
Wells in Progress		0			0			0			362,076			0
Pipelines		0			0			0			1,509,601			113,107
Total Property and Equipment		7,870,572			4,370,549			1,500,000			14,835,284			4,583,828
Less: Accumulated Depreciation, Depletion and Amortization		(641,958	)		(978,623	)		(134,914	)		(5,122,830	)		(453,807	)
Net Property and Equipment		7,228,614			3,391,926			1,365,086			9,712,454			4,130,021
Other Assets
Other Assets—Net		0			60,647			0			(462,144	)		0
Long-Term Derivative Instruments		0			0			0			0			0
Total Other Assets		0			60,647			0			(462,144	)		0
Total Assets	$	9,537,329		$	5,144,026		$	1,783,214		$	11,458,515		$	4,840,739
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable and Accrued Expenses	$	3,295,555		$	773,265		$	8,000		$	1,210,601		$	187,507
Short-Term Derivative Instruments		1,812,652			3,128,178			0			0			0
Accrued Distributions		3,100,000			0			300,000			0			0
Lines of Credit		0			2,549,016			0			3,292,755			0
Current Portion of Long-Term Debt		83,454			0			0			30,000			3,422
Related Party Payable		317,894			8,136,423			10,374			42,119			981,988
Total Current Liabilities		8,609,555			14,586,882			318,374			4,575,475			1,172,917
Long-Term Liabilities
Long-Term Debt		0			0			0			0			3,000,000
Other Loans and Notes Payable—Long-Term Portion		232,839			0			0			81,474			19,832
Long-Term Derivative Instruments		2,032,837			790,899			0			143,385			0
Participation Liability—Net		0			0			0			0			574,254
Other Liabilities		0			0			0			325,036			0
Asset Retirement Obligation		854,041			854,042			0			206,381			116,538
Total Long-Term Liabilities		3,119,717			1,644,941			0			756,276			3,710,624
Total Liabilities		11,729,272			16,231,823			318,374			5,331,751			4,883,541
Minority Interests		0			0			1,400,885			4,988,911			(120,165	)
Owners’ Equity
Common Stock		1,000			0			0			0			0
Additional Paid-In Capital		1,460,000			0			0			0			0
Accumulated Stockholders’ (Deficit)		(3,652,943	)		0			0			0			0
Partners’ and Members’ Equity (Deficit)		0			(11,087,797	)		63,955			1,137,853			77,363
Total Owners’ Equity (Deficit)		(2,191,943	)		(11,087,797	)		63,955			1,137,853			77,363
Total Liabilities, Minority Interests and Owners’ Equity (Deficit)	$	9,537,329		$	5,144,026		$	1,783,214		$	11,458,515		$	4,840,739

F-112

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING BALANCE SHEET

December 31, 2005

	Midland Exploration, LP			Rex Energy, LP			Rex Energy II, LP			Rex Energy II Alpha, LP			New Albany— Indiana, LLC		Rex Energy Operating Corp.			Eliminations			Total
ASSETS
Current Assets
Cash and Cash Equivalents	$	18,778		$	54,692		$	1,630,452		$	6,005		$	0	$	160,297		$	0		$	2,687,550
Restricted Cash		0			0			0			0			0		0			0			500,000
Accounts Receivable		142,808			37,525			1,066,935			18,219			0		391,583			(1,770,930	)		5,349,373
Short-Term Derivative Instruments		0			0			0			0			0		0			0			0
Inventory, Prepaid Expenses and Other		9,436			0			147,789			494			0		71,352			0			785,731
Total Current Assets		171,022			92,217			2,845,176			24,718			0		623,232			(1,770,930	)		9,322,654
Property and Equipment
Evaluated Oil and Gas Properties		659,170			113,878			14,663,687			728,122			0		0			0			45,030,383
Unevaluated Oil and Gas Properties		0			0			246,193			1,329			0		0			0			1,261,167
Other Property and Equipment		0			0			2,254			0			0		76,790			0			1,375,322
Wells in Progress		0			52,805			208,378			19,859			0		0			0			643,118
Pipelines		0			0			0			0			0		0			0			1,622,708
Total Property and Equipment		659,170			166,683			15,120,512			749,310			0		76,790			0			49,932,698
Less: Accumulated Depreciation, Depletion and Amortization		(210,684	)		(2,636	)		(110,774	)		(5,315	)		0		(6,301	)		0			(7,667,842	)
Net Property and Equipment		448,486			164,047			15,009,738			743,995			0		70,489			0			42,264,856
Other Assets
Other Assets—Net		0			2,982,179			0			0			3,500,000		1,760,000			(4,137,578	)		3,703,104
Long-Term Derivative Instruments		0			0			0			0			0		0			0			0
Total Other Assets		0			2,982,179			0			0			3,500,000		1,760,000			(4,137,578	)		3,703,104
Total Assets	$	619,508		$	3,238,443		$	17,854,914		$	768,713		$	3,500,000	$	2,453,721		$	(5,908,508	)	$	55,290,614
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable and Accrued Expenses	$	7,829		$	0		$	1,665,131		$	23,228		$	0	$	553,650		$	0		$	7,724,766
Short-Term Derivative Instruments		0			0			194,837			0			0		0			0			5,135,667
Accrued Distributions		127,979			0			82,714			11,298			0		0			0			3,621,991
Lines of Credit		0			0			0			0			0		0			0			5,841,771
Current Portion of Long-Term Debt		0			0			0			0			0		4,641			0			121,517
Related Party Payable		28,900			40,877			41,947			4,486			0		2,017,445			(1,770,931	)		9,851,522
Total Current Liabilities		164,708			40,877			1,984,629			39,012			0		2,575,736			(1,770,931	)		32,297,234
Long-Term Liabilities
Long-Term Debt		0			0			0			0			0		0			0			3,000,000
Other Loans and Notes Payable—Long-Term Portion		0			0			0			0			0		25,902			0			360,047
Long-Term Derivative Instruments		0			0			198,534			0			0		0			0			3,165,655
Participation Liability—Net		0			0			0			0			0		0			0			574,254
Other Liabilities		0			0			0			0			0		0			0			325,036
Asset Retirement Obligation		7,613			0			288,206			31,337			0		0			0			2,358,158
Total Long-Term Liabilities		7,613			0			486,740			31,337			0		25,902			0			9,783,150
Total Liabilities		172,321			40,877			2,471,369			70,349			0		2,601,638			(1,770,931	)		42,080,384
Minority Interests		439,551			2,484,975			13,854,786			698,364			3,479,000		(59,167	)		(3,037,172	)		24,129,968
Owners’ Equity
Common Stock		0			0			0			0			0		60			0			1,060
Additional Paid-In Capital		0			0			0			0			0		0			0			1,460,000
Accumulated Stockholders’ (Deficit)		0			0			0			0			0		(88,810	)		0			(3,741,753	)
Partners’ and Members’ Equity (Deficit)		7,636			712,591			1,528,759			0			21,000		0			(1,100,405	)		(8,639,045	)
Total Owners’ Equity (Deficit)		7,636			712,591			1,528,759			0			21,000		(88,750	)		(1,100,405	)		(10,919,738	)
Total Liabilities, Minority Interests and Owners’ Equity (Deficit)	$	619,508		$	3,238,443		$	17,854,914		$	768,713		$	3,500,000	$	2,453,721		$	(5,908,508	)	$	55,290,614

F-113

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2006

	PennTex Resources Illinois, Inc.			PennTex Resources, LP			Rex Energy Royalties, LP		Douglas Oil & Gas, LP			Douglas Westmoreland, LP			Midland Exploration, LP
OPERATING REVENUE
Oil and Natural Gas Sales	$	10,011,844		$	9,464,024		$	686,238	$	2,926,180		$	2,715,674		$	401,754
Other Operating Revenue		0			0			0		123,552			0			0
Realized Gain (Loss) on Hedges		(2,110,677	)		(3,278,082	)		0		201,631			537,375			0
Unrealized Gain (Loss) on Hedges		1,769,844			2,912,500			0		445,019			301,634			0
TOTAL OPERATING REVENUE		9,671,011			9,098,442		$	686,238	$	3,696,382		$	3,554,683		$	401,754
OPERATING EXPENSES
Operating Expenses		5,211,366			5,126,786			0		754,598			336,939			86,914
Production Taxes		34,562			77,163			0		68,863			0			40,527
Gas Contract Purchases		0			0			0		0			428,379			0
General and Administrative Expense (Income)		(99,965	)		744,919			83,121		513,843			149,223			60,305
Accretion Expense on Asset Retirement Obligation		82,681			78,972			0		20,880			12,044			762
Impairment Charge on Oil and Gas Properties		0			0			0		0			0			0
Depreciation, Depletion, and Amortization		1,010,049			671,668			123,249		1,548,642			570,499			161,881
TOTAL OPERATING EXPENSES		6,238,693			6,699,508			206,370		2,906,826			1,497,084			350,389
INCOME (LOSS) FROM OPERATIONS		3,432,318			2,398,934			479,868		789,556			2,057,599			51,365
OTHER INCOME (EXPENSE)
Interest Income		2,413			36,143			0		4,589			15,402			0
Interest Expense		(224,847	)		(1,138,148	)		0		(458,652	)		(2,259,530	)		0
Gain (Loss) on Sale of Oil and Gas Properties		0			0			0		91,416			0			0
Other Income (Expense)		(32,706	)		(27,723	)		0		51,038			0			0
TOTAL OTHER INCOME (EXPENSE)		(255,140	)		(1,129,728	)		0		(311,609	)		(2,244,128	)		0
NET INCOME (LOSS) BEFORE MINORITY INTEREST		3,177,178			1,269,206			479,868		477,947			(186,529	)		51,365
MINORITY INTEREST SHARE OF INCOME (LOSS)		0			0			455,107		412,468			(160,975	)		50,071
NET INCOME (LOSS)	$	3,177,178		$	1,269,206		$	24,761	$	65,479		$	(25,554	)	$	1,294

F-114

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2006

	Rex Energy, LP		Rex Energy II, LP			Rex Energy II Alpha, LP			Rex Energy III, LLC			Rex Energy IV, LLC			New Albany— Indiana, LLC			Rex Energy Operating Corp.			Eliminations			Total
OPERATING REVENUE
Oil and Natural Gas Sales	$	73,997	$	8,625,042		$	424,403		$	4,273,371		$	3,993,490		$	0		$	0		$	0		$	43,596,017
Other Operating Revenue		0		336,061			9,969			0			0			0			0			0			469,582
Realized Gain (Loss) on Hedges		0		(60,499	)		0			182,570			91,335			0			0			0			(4,436,347	)
Unrealized Gain (Loss) on Hedges		0		253,806			(10,923	)		576,607			(1,205,267	)		0			0			0			5,043,220
TOTAL OPERATING REVENUE	$	73,997	$	9,154,410		$	423,449		$	5,032,548		$	2,879,558		$	0		$	0		$	0		$	44,672,472
OPERATING EXPENSES
Operating Expenses		12,488		2,082,919			103,695			1,209,279			2,393,285			35,667			0			(3,099,342	)		14,254,594
Production Taxes		0		237,830			9,310			54,581			28,246			0			0			0			551,082
Gas Contract Purchases		0		0			0			0			0			0			0			0			428,379
General and Administrative Expense (Income)		3,780		855,473			31,979			148,827			661,263			161,515			7,820,778			(4,922,922	)		6,212,139
Accretion Expense on Asset Retirement Obligation		0		73,371			3,605			59,304			143,882			0			0			0			475,501
Impairment Charge on Oil and Gas Properties		0		0			0			0			0			0			0			0			0
Depreciation, Depletion, and Amortization		34,697		2,949,433			154,585			2,019,796			1,391,061			0			111,245			0			10,746,805
TOTAL OPERATING EXPENSES		50,965		6,199,026			303,174			3,491,787			4,617,737			197,182			7,932,023			(8,022,264	)		32,668,500
INCOME (LOSS) FROM OPERATIONS		23,032		2,955,384			120,275			1,540,761			(1,738,179	)		(197,182	)		(7,932,023	)		8,022,264			12,003,972
OTHER INCOME (EXPENSE)
Interest Income		0		10,151			858			1,151			0			21,230			1,747			0			93,684
Interest Expense		0		(274,708	)		0			(926,026	)		(801,119	)		0			(26,993	)		0			(6,110,023	)
Gain (Loss) on Sale of Oil and Gas Properties		0		0			0			0			0			0			0			0			91,416
Other Income (Expense)		289,397		(135,278	)		0			14,801			0			0			8,022,264			(8,313,506	)		(131,713	)
TOTAL OTHER INCOME (EXPENSE)		289,397		(399,835	)		858			(910,074	)		(801,119	)		21,230			7,997,018			(8,313,506	)		(6,056,636	)
NET INCOME (LOSS) BEFORE MINORITY INTEREST		312,429		2,555,549			121,133			630,687			(2,539,298	)		(175,952	)		64,995			(291,242	)		5,947,336
MINORITY INTEREST SHARE OF INCOME (LOSS)		242,820		2,271,883			121,133			337,418			(1,269,649	)		(126,615	)		25,998			(226,004	)		2,133,655
NET INCOME (LOSS)	$	69,609	$	283,666		$	0		$	293,269		$	(1,269,649	)	$	(49,337	)	$	38,997		$	(65,238	)	$	3,813,681

F-115

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2005

	PennTex Resources Illinois, Inc.			PennTex Resources, LP			Rex Energy Royalties, LP			Douglas Oil & Gas, LP			Douglas Westmoreland, LP
OPERATING REVENUE
Oil and Natural Gas Sales	$	9,102,896		$	11,446,404		$	790,720		$	3,669,512		$	2,818,821
Other Operating Revenue		0			62,099			0			208,041			0
Realized Gain (Loss) on Hedges		(4,599,517	)		(3,013,045	)		(23,195	)		(197,973	)		(98,562	)
Unrealized Gain (Loss) on Hedges		(2,480,740	)		(2,551,546	)		0			(115,385	)		0
TOTAL OPERATING REVENUE		2,022,639			5,943,912		$	767,525		$	3,564,195		$	2,720,259
OPERATING EXPENSES
Operating Expenses		5,023,152			6,098,273			0			875,439			327,833
Production Taxes		78,301			232,449			0			68,138			0
Gas Contract Purchases		0			0			0			0			402,317
General and Administrative Expense (Income)		397,365			701,548			51,114			474,306			57,358
Accretion Expense on Asset Retirement Obligation		77,640			78,041			0			6,971			6,990
Impairment Charge on Oil and Gas Properties		0			0			0			0			0
Depreciation, Depletion, and Amortization		641,958			1,180,997			80,747			627,288			350,000
TOTAL OPERATING EXPENSES		6,218,416			8,291,308			131,861			2,052,142			1,144,498
INCOME (LOSS) FROM OPERATIONS		(4,195,777	)		(2,347,396	)		635,664			1,512,053			1,575,761
OTHER INCOME (EXPENSE)
Interest Income		9,246			16,170			0			30,431			18,490
Interest Expense		(118,118	)		(233,661	)		0			(269,648	)		(1,073,650	)
Gain (Loss) on Sale of Oil and Gas Properties		0			1,203,528			0			(186,983	)		0
Other Income (Expense)		8,688			0			0			235,990			0
TOTAL OTHER INCOME (EXPENSE)		(100,184	)		986,037			0			(190,210	)		(1,055,160	)
NET INCOME (LOSS) BEFORE MINORITY INTEREST		(4,295,961	)		(1,361,359	)		635,664			1,321,843			520,601
MINORITY INTEREST SHARE OF INCOME (LOSS)		0			(408,408	)		602,864			1,140,751			449,279
NET INCOME (LOSS)	$	(4,295,961	)	$	(952,951	)	$	32,800		$	181,092		$	71,322

F-116

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO THE COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2005

	Midland Exploration, LP		Rex Energy, LP		Rex Energy II, LP			Rex Energy II Alpha, LP		New Albany— Indiana, LLC		Rex Energy Operating Corp.			Eliminations			Total
OPERATING REVENUE
Oil and Natural Gas Sales	$	472,697	$	28,101	$	1,092,337		$	96,102	$	0	$	0		$	0		$	29,517,590
Other Operating Revenue		0		0		0			0		0		0			0			270,140
Realized Gain (Loss) on Hedges		0		0		2,814			0		0		0			0			(7,929,478	)
Unrealized Gain (Loss) on Hedges		0		0		(393,372	)		0		0		0			0			(5,541,043	)
TOTAL OPERATING REVENUE	$	472,697	$	28,101	$	701,779		$	96,102	$	0	$	0		$	0		$	16,317,209
OPERATING EXPENSES
Operating Expenses		22,674		12,443		254,320			27,085		0		0			(1,788,780	)		10,852,439
Production Taxes		35,906		0		47,747			3,682		0		0			0			466,223
Gas Contract Purchases		0		0		0			0		0		0			0			402,317
General and Administrative Expense (Income)		34,234		575		220,211			24,109		0		6,443,791			(4,615,679	)		3,788,932
Accretion Expense on Asset Retirement Obligation		1,321		0		25,946			2,849		0		0			0			199,758
Impairment Charge on Oil and Gas Properties		107,119		0		0			0		0		0			0			107,119
Depreciation, Depletion, and Amortization		115,000		2,636		110,000			5,315		0		6,301			0			3,120,242
TOTAL OPERATING EXPENSES		316,254		15,654		658,224			63,040		0		6,450,092			(6,404,459	)		18,937,030
INCOME (LOSS) FROM OPERATIONS		156,443		12,447		43,555			33,062		0		(6,450,092	)		6,404,459			(2,619,821	)
OTHER INCOME (EXPENSE)
Interest Income		0		0		363,308			6,793		0		0			0			444,438
Interest Expense		0		0		0			0		0		(2,384	)		0			(1,697,461	)
Gain (Loss) on Sale of Oil and Gas Properties		0		0		0			0		0		0			0			1,016,545
Other Income (Expense)		0		800,376		0			0		0		6,404,459			(7,233,835	)		215,678
TOTAL OTHER INCOME (EXPENSE)		0		800,376		363,308			6,793		0		6,402,075			(7,233,835	)		(20,800	)
NET INCOME (LOSS) BEFORE MINORITY INTEREST		156,443		812,823		406,863			39,855		0		(48,017	)		(829,376	)		(2,640,621	)
MINORITY INTEREST SHARE OF INCOME (LOSS)		152,501		631,726		361,701			39,855		0		(19,207	)		(647,079	)		2,303,982
NET INCOME (LOSS)	$	3,942	$	181,097	$	45,162		$	0	$	0	$	(28,810	)	$	(182,297	)	$	(4,944,603	)

F-117

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2004

	PennTex Resources, LP			Rex Energy Royalties, LP			Douglas Oil & Gas, LP
OPERATING REVENUE
Oil and Natural Gas Sales	$	9,962,408		$	404,478		$	2,631,737
Other Operating Revenue		0			0			721,412
Realized Gain (Loss) on Hedges		(659,380	)		(31,645	)		(218,412	)
Unrealized Gain (Loss) on Hedges		(1,367,531	)		0			(28,000	)
TOTAL OPERATING REVENUE		7,935,497		$	372,833		$	3,106,737
OPERATING EXPENSES
Operating Expenses		5,088,592			0			1,096,609
Production Taxes		268,000			0			0
Gas Contract Purchases		0			0			0
General and Administrative Expense		263,160			26,219			1,712,373
Accretion Expense on Asset Retirement Obligation		90,001			0			18,156
Impairment Charge on Oil and Gas Properties		0			0			3,024,267
Depreciation, Depletion, and Amortization		1,125,012			54,166			606,038
TOTAL OPERATING EXPENSES		6,834,765			80,385			6,457,443
INCOME (LOSS) FROM OPERATIONS		1,100,732			292,448			(3,350,706	)
OTHER INCOME (EXPENSE)
Interest Income		0			0			5,972
Interest Expense		(325,020	)		0			(178,019	)
Gain (Loss) on Sale of Oil and Gas Properties		617,697			0			0
Other Income (Expense)		(5,955	)		0			36,212
TOTAL OTHER INCOME (EXPENSE)		286,722			0			(135,835	)
NET INCOME (LOSS) BEFORE MINORITY INTEREST		1,387,454			292,448			(3,486,541	)
MINORITY INTEREST SHARE OF INCOME (LOSS)		554,982			277,358			(3,008,885	)
NET INCOME (LOSS)	$	832,472		$	15,090		$	(477,656	)

F-118

FOUNDING COMPANIES OF REX ENERGY CORPORATION

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2004

	Douglas Westmoreland, LP			Midland Exploration, LP		Rex Energy, LP			Rex Energy II, LP			Eliminations			Total
OPERATING REVENUE
Oil and Natural Gas Sales	$	932,482		$	219,248	$	0		$	8,559		$	0		$	14,158,912
Other Operating Revenue		0			0		0			0			(24,000	)		697,412
Realized Gain (Loss) on Hedges		(32,074	)		0		0			0			0			(941,511	)
Unrealized Gain (Loss) on Hedges		0			0		0			0			0			(1,395,531	)
TOTAL OPERATING REVENUE		900,408		$	219,248	$	0		$	8,559		$	(24,000	)	$	12,519,282
OPERATING EXPENSES
Operating Expenses		169,606			57,308		0			792			(150,648	)		6,262,259
Production Taxes		0			0		0			0			0			268,000
Gas Contract Purchases		177,515			0		0			0			0			177,515
General and Administrative Expense		33,083			30,088		952			36,463			126,648			2,228,986
Accretion Expense on Asset Retirement Obligation		12,881			0		0			970			0			122,008
Impairment Charge on Oil and Gas Properties		0			0		0			0			0			3,024,267
Depreciation, Depletion, and Amortization		103,807			26,949		0			1,285			0			1,917,257
TOTAL OPERATING EXPENSES		496,892			114,345		952			39,510			(24,000	)		14,000,292
INCOME (LOSS) FROM OPERATIONS		403,516			104,903		(952	)		(30,951	)		0			(1,481,010	)
OTHER INCOME (EXPENSE)
Interest Income		0			0		21			12,638			0			18,631
Interest Expense		(364,347	)		0		0			0			0			(867,386	)
Gain (Loss) on Sale of Oil and Gas Properties		0			41,667		0			0			0			659,364
Other Income (Expense)		0			0		(1,999,236	)		0			1,947,808			(21,171	)
TOTAL OTHER INCOME (EXPENSE)		(364,347	)		41,667		(1,999,215	)		12,638			1,947,808			(210,562	)
NET INCOME (LOSS) BEFORE MINORITY INTEREST		39,169			146,570		(2,000,167	)		(18,313	)		1,947,808			(1,691,572	)
MINORITY INTEREST SHARE OF INCOME (LOSS)		33,803			142,876		(1,554,530	)		(16,280	)		1,509,054			(2,061,623	)
NET INCOME (LOSS)	$	5,366		$	3,694	$	(445,637	)	$	(2,033	)	$	438,754		$	370,051

F-119

Douglas Oil & Gas Limited Partnership

F-120

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Douglas Oil & Gas Limited Partnership

State College, Pennsylvania

We have audited the accompanying consolidated balance sheets of Douglas Oil & Gas Limited Partnership as of December 31, 2006 and 2005 and the related consolidated statements of operations, changes in partners’ equity and cash flows for each of the three years in the period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Douglas Oil & Gas Limited Partnership as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

Pittsburgh, Pennsylvania

March 15, 2007

F-121

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

CONSOLIDATED BALANCE SHEETS

	December 31,
	2006			2005
ASSETS
CURRENT ASSETS
Cash	$	65,727		$	835,393
Production Receivable—Net of Allowance for Doubtful Accounts of $0 and $2,347 for 2006 and 2005		1,544,077			1,368,446
Joint Interest Billing Receivables		44,612			151,009
Other Receivables		7,733			0
Financial Instruments—Current Portion		802,734			0
Related Party Receivable		176,071			94,135
Prepaid Expenses		97,955			43,008
TOTAL CURRENT ASSETS		2,738,909			2,491,991
OIL AND GAS PROPERTY AND EQUIPMENT
Undeveloped Properties		140,443			1,013,645
Wells In Progress		189,293			363,861
Proved Developed Oil and Natural Gas Properties		21,224,544			16,352,442
Pipelines		1,764,439			1,622,708
Transportation Vehicles and Other Equipment		721,066			727,411
Total Oil and Gas Property and Equipment		24,039,785			20,080,067
Less: Accumulated Depreciation, Depletion, and Amortization		(8,174,889	)		(5,787,321	)
NET OIL AND GAS PROPERTY AND EQUIPMENT		15,864,896			14,292,746
OTHER ASSETS
Investments in Related Parties		1,714,297			10,212
Deposits and Other Assets		55,000			20,400
Loan Costs—Net of Accumulated Amortization		102,340			57,057
TOTAL OTHER ASSETS		1,871,637			87,669
TOTAL ASSETS	$	20,475,442		$	16,872,406
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES
Line of Credit	$	0		$	3,292,755
Accounts Payable		735,360			242,288
Production Payable		53,533			945,846
Current Portion—Vehicle Loans		26,692			33,422
Drilling Advances		0			75,060
Accrued Expenses		151,225			142,743
Accrued Distributions		102,465			127,979
Related Party Payable		44,487			456,838
TOTAL CURRENT LIABILITIES		1,113,762			5,316,931
OTHER LIABILITIES
Term Loans		8,941,586			3,000,000
Discount on Term Loan—Norguard—Net of Amortization		0			(165,746	)
Participation Liability		2,141,109			740,000
Asset Retirement Obligation		370,537			330,532
Other Deposits		322,046			325,036
Vehicle Loans		89,561			101,306
Financial Instrument Payable		199,466			143,385
TOTAL OTHER LIABILITIES		12,064,305			4,474,513
TOTAL LIABILITIES		13,178,067			9,791,444
CUMULATIVE NON-CONTROLLING OR MINORITY INTEREST IN SUBSIDIARIES		1,500,394			399,993
COMMITMENTS AND CONTINGENCIES (Note 4)
PARTNERS’ EQUITY		5,796,981			6,680,969
TOTAL LIABILITIES, NON-CONTROLLING OR MINORITY INTERESTS AND PARTNERS’ EQUITY	$	20,475,442		$	16,872,406

SEE ACCOMPANYING NOTES.

F-122

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2006			2005			2004
OPERATING REVENUE
Oil and Natural Gas Sales	$	6,729,846		$	6,961,030		$	3,783,467
Pipeline Revenue		97,199			106,761			137,594
Realized Gain (Loss) on Hedges		739,006			(296,535	)		(250,486	)
Unrealized Gain (Loss) on Hedges		746,653			(115,385	)		(28,000	)
Well Service Charges and Other Fees		2,353			77,280			559,818
TOTAL OPERATING REVENUE		8,315,057			6,733,151			4,202,393
OPERATING EXPENSES
Operating Expenses		1,196,643			1,225,946			1,199,850
Pipeline		0			0			123,673
Production Taxes		109,390			104,044			0
Gas Contract Purchases		428,379			402,317			177,515
General and Administrative		764,300			541,898			1,751,544
Accretion Expense		33,686			15,282			31,037
Impairment Charge on Oil and Gas Properties		0			107,119			3,024,267
Depreciation, Depletion, and Amortization		2,404,271			1,092,288			736,794
TOTAL OPERATING EXPENSES		4,936,669			3,488,894			7,044,680
INCOME (LOSS) FROM OPERATIONS		3,378,388			3,244,257			(2,842,287	)
OTHER INCOME (EXPENSE)
Interest Income		19,991			48,921			5,972
Interest Expense		(2,718,182	)		(1,343,298	)		(542,366	)
Gain (Loss) on Sale of Oil and Gas Properties		91,416			(186,983	)		41,667
Other Income		10,133			206,990			9,714
TOTAL OTHER INCOME (EXPENSE)		(2,596,642	)		(1,274,370	)		(485,013	)
TOTAL INCOME (LOSS) BEFORE MINORITY INTEREST		781,746			1,969,887			(3,327,300	)
NON-CONTROLLING OR MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES		520,122			132,832			120,247
NET INCOME	$	261,624		$	1,837,055		$	(3,447,547	)

SEE ACCOMPANYING NOTES.

F-123

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

YEARS ENDED DECEMBER 31, 2006, 2005, AND 2004

	Partners’ Equity
BALANCE—January 1, 2004	$	10,470,190
DISTRIBUTIONS TO PARTNERS		(878,674	)
NET LOSS		(3,447,547	)
BALANCE—December 31, 2004	$	6,143,969
DISTRIBUTIONS TO PARTNERS		(1,300,054	)
NET INCOME		1,837,055
BALANCE—December 31, 2005	$	6,680,970
DISTRIBUTIONS TO PARTNERS		(1,145,613	)
NET INCOME		261,624
BALANCE—December 31, 2006	$	5,796,981

SEE ACCOMPANYING NOTES.

F-124

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	261,624		$	1,837,055		$	(3,447,547	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Minority Interest in Subsidiary Income		520,122			132,832			120,247
Depreciation, Depletion, and Amortization		2,404,271			1,092,288			736,794
Unrealized (Gain) Loss on Hedges		(746,653	)		115,385			28,000
Loss on Investment in Affiliate		19,530			0			(29,245	)
Impairment of Oil and Gas Properties		0			107,119			3,024,267
Accretion Expense on Asset Retirement Obligation		33,686			15,282			31,037
Amortization of Participation Liability		1,566,855			443,634			130,620
(Gain) Loss on Sale of Oil and Gas Properties and Other Assets		(91,416	)		186,983			(41,667	)
(Increase) Decrease in
Accounts Receivable		(76,967	)		(901,407	)		(351,911	)
Change in Related Party Receivables and Payables		(87,244	)		302,263			945
Prepaid Expenses		(54,947	)		59,107			(85,920	)
Increase (Decrease) in
Accounts Payable		493,072			(1,215,904	)		980,693
Production Payable		(892,313	)		1,153,310			768,003
Other Payables		(6,730	)		0			0
Accrued Expenses		482			9,585			10,945
NET CASH PROVIDED BY OPERATING ACTIVITIES		3,343,372			3,337,532			1,875,261
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Sale of Oil and Gas Properties, Prospect, or Other Assets		157,066			550,000			366,945
Investments in Affiliates		(1,733,827	)		140,000			(140,000	)
Distributions Received from Investments		0			12,500			6,533
Deposits and Other Assets		(34,600	)		79,776			(100,000	)
Drilling Advances		(75,060	)		(405,629	)		182,763
Wells In Progress		0			138,181			197,227
Acquisitions of Undeveloped Acreage		(121,925	)		0			0
Development of Oil and Gas Properties and Related Equipment		(2,339,582	)		(2,090,841	)		(6,750,498	)
NET CASH USED IN INVESTING ACTIVITIES		(4,147,928	)		(1,576,013	)		(6,237,030	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Debts		8,941,586			470,069			6,747,754
Repayments of Debts		(6,277,808	)		(813,594	)		(1,725,285	)
Restricted Cash		0			0			746,750
Payments of Financing Costs		(283,403	)		0			(102,628	)
Capital Contributions from Non-Controlling or Minority Interest Holders		0			10,081			40,000
Distributions to Non-Controlling or Minority Interest Holders		(1,199,872	)		(316,978	)		(120,481	)
Accrued Distributions		0			127,979			0
Distributions to Partners		(1,145,613	)		(1,172,075	)		(878,674	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		34,890			(1,694,518	)		4,707,436
NET INCREASE IN CASH		(769,666	)		67,001			345,667
CASH—BEGINNING		835,393			768,392			422,725
CASH—ENDING	$	65,727		$	835,393		$	768,392
SUPPLEMENTAL DISCLOSURES
Interest Paid	$	3,360,656		$	881,661		$	360,876
Non-Cash Activities
Accrued Distributions	$	102,468		$	127,979		$	0
Contributions of Capital Assets at Formation by Minority Interest Holders	$	0		$	0		$	509,219

SEE ACCOMPANYING NOTES.

F-125

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The December 31, 2005 consolidated financial statements include Douglas Oil & Gas Limited Partnership, a Delaware limited partnership (“Douglas Oil & Gas”), Douglas Westmoreland Limited Partnership, a Delaware limited partnership (“Douglas Westmoreland”), and Midland Exploration Limited Partnership, a Delaware limited partnership (“Midland”).

Douglas Oil & Gas is the general partner of Midland and owns an 18.42 percent interest in the company. Douglas Oil & Gas owns a 99.0 percent limited partnership interest in Douglas Westmoreland. In accordance with EITF 04-5—Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights, management of Douglas Oil & Gas determined that Douglas Oil & Gas controls Douglas Westmoreland and Midland and, therefore, the accounts of Douglas Westmoreland and Midland have been consolidated in these financial statements. EITF 04-5 was effective for the first reporting period beginning after fiscal periods beginning after December 15, 2005, or January 1, 2006. Management of Douglas Oil & Gas applied early adoption of this EITF when determining the entities to be consolidated. All material intercompany balances and transactions have been eliminated.

Upon further review and application of EITF 04-5, management of Douglas Oil & Gas determined that Rex Energy Royalties Limited Partnership, a Delaware limited partnership (“Rex Royalties”), should be consolidated upon the effective date. As of December 31, 2004, Douglas Oil & Gas owned a 10.0 percent interest in the partnership and served as its general partner. In addition, under the terms of Rex Royalties’ limited partnership agreement, Douglas Oil & Gas held the right to receive an additional 50.0 percent economic interest in Rex Royalties upon the “return date,” which is defined as the date upon which the limited partners of Rex Royalties have received, through distributions from Rex Royalties, their respective initial capital contributions in Rex Royalties. On January 1, 2005, Douglas Oil & Gas sold its 10.0 percent economic interest in Rex Royalties to Shaner & Hulburt Capital Partners Limited Partnership, a Delaware limited partnership (“Shaner Hulburt Capital Partners”) (a related party) for $140,000, which represented the amount of Douglas Oil & Gas’s original capital investment in Rex Royalties. No gain or loss was recognized on the sale. Douglas Oil & Gas remained the general partner of Rex Royalties following the sale. Under the terms of the sale agreement with Shaner Hulburt Capital Partners, Douglas Oil & Gas retained the right to receive an additional 25.0 percent economic interest in Rex Royalties upon the return date, but sold the remaining 25.0 percent economic interest to Shaner Hulburt Capital Partners in connection with the sale.

The December 31, 2006 consolidated financial statements include Douglas Oil & Gas, Douglas Westmoreland, Midland and Rex Royalties, such entities being collectively referred to herein as “the Company”. The December 31, 2005 consolidated financial statements account for Rex Royalties under the equity method and do not include the effects of consolidation under EITF 04-5. Refer to Note 1: “Investment in Affiliates.” All material intercompany balances and transactions have been eliminated.

Description of Businesses

Douglas Oil & Gas engages in the exploration, development, and production of oil and natural gas reserves in participation with other investors or limited partners. Douglas Oil & Gas has ownership interests in approximately 521 wells located in the states of Texas, New Mexico, and Pennsylvania. Douglas Oil & Gas receives fees from other working interest owners for drilling and operating these wells. Douglas Oil & Gas is

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DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

owned by Rex Energy, LLC (1.0 percent general partner), Rex Energy Limited Partnership (60.55 percent limited partner) and Douglas Oil & Gas, Inc. (38.45 percent limited partner).

Douglas Westmoreland engages in the exploration, acquisition, management, leasing, development, and extraction of natural gas from underground reservoirs. Douglas Westmoreland operates and has a 100.0 percent working interest in approximately 49 proved and producing natural gas wells located in Westmoreland County, Pennsylvania. Douglas Oil & Gas owns a 99.0 percent limited partnership interest in Douglas Westmoreland.

Midland engages in the business of evaluating, generating, and/or acquiring oil and natural gas prospects or producing properties in various locations throughout the Permian Basin in the states of Texas and New Mexico. Midland has ownership interests in approximately 32 wells. Douglas Oil & Gas is an 18.42 percent general partner of Midland.

Rex Royalties engages in the business of acquiring, owning, operating, managing, leasing, developing, or otherwise disposing of royalty interests in oil and natural gas properties. Rex Royalties does not engage in the acquisition of working interests in oil and gas properties, or engage in the exploration, development, production, or operational activities with respect to any oil and gas property. It owns royalty interests in approximately 49 proved and producing natural gas wells located in Westmoreland County, Pennsylvania. Douglas Oil & Gas is the general partner of Rex Royalties.

Revenue Recognition

Natural gas and oil revenue is recognized when the oil and natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. In each case it is the measurement of the purchaser that determines the amount of oil or gas purchased (although there are provisions for challenging these measurements if we believe the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil and natural gas production is at our applicable field gathering system; therefore, we do not incur transportation costs related to our sales of oil and natural gas production. The Company does not currently participate in any gas-balancing arrangements. Transportation revenue is recognized as oil and natural gas is transported. The Company uses the allowance method to account for uncollectible accounts receivable. At December 31, 2006 and 2005, management determined the allowance for uncollectible receivables to be $0 and $2,347, respectively.

Royalty Revenue Recognition

Rex Royalties’ royalty revenue, from Douglas Westmoreland Limited Partnership, is earned as natural gas is delivered, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Rex Royalties uses the allowance method to account for uncollectible accounts receivable. At December 31, 2006 and 2005, management determined there was no allowance for doubtful accounts.

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DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Distributions to Class A Limited Partners

Class A limited partners of Rex Royalties are entitled to receive priority distributions. Priority distributions are defined as a preferential distribution of net cash flow equal to 8.0 percent per annum of the Class A limited partners’ undistributed capital accounts. Remaining net cash flow is distributed to partners of the Company in accordance with their respective percentage interest in the Company. Additional excess cash flow distributions to the Class A limited partners may be authorized, which reduces their capital accounts. Rex Royalties distributed $49,073 and $103,467 in priority distributions and $886,000 and $322,500 in excess cash flow distributions for the years ended December 31, 2006 and 2005, respectively. At December 31, 2005, Rex Royalties accrued $300,000 of excess distributions that were paid in February 2006.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, long-term debt, a participation liability associated with a long-term debt, fixed rate swap contracts, and commodity collars.

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

Income Taxes

The Company is treated as a partnership for federal and state income tax purposes. Accordingly, income taxes are not reflected in the consolidated financial statements because the resulting profit or loss is included in the income tax returns of the individual partners.

Production Receivable

Production receivables correspond to approximately two months of oil and natural gas revenue extracted and sold to buyers. The production receivable is valued at the invoiced amount and does not bear interest. The Company has assessed the financial strength of its customers and recorded bad debts as necessary.

Joint Interest Billing Receivable

Joint interest billing receivables represent the Company’s billings to the non-operators associated with the operation of wells and are based on those owners’ working interests in the wells.

Accounting Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting period. Accordingly, actual results could differ from those estimates. Among the more sensitive of the estimates involves determining the proved reserves from which depletion expense is calculated, calculating the plugging liability, and determining the future net cash flows from which asset impairment, if any, is ascertained.

Reclassification

The prior year financial statements have been reclassified to conform to current year presentation.

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DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Non-Controlling or Minority Interests

Douglas Oil & Gas owns 99.0 percent limited partnership interest in Douglas Westmoreland at December 31, 2006 and 2005. The remaining 1.0 interest in Douglas Westmoreland is owned by its general partner, Rex Energy LLC, a Delaware limited liability company. Rex Energy LLC’s allocation of net assets and profits are reflected in the Consolidated Balance Sheets and Statements of Operations.

Douglas Oil & Gas owns 18.42 percent interest in Midland at December 31, 2006 and 2005. The remaining 81.58 percent interest in Midland is owned by the limited partners of Midland. The limited partners’ allocation of net assets and profits are reflected in the Consolidated Balance Sheets and Statements of Operations.

All of the ownership and activity of Rex Royalties is reflected in Non-Controlling or Minority Interest holders at December 31, 2006. The Minority Interest Holders’ allocation of net assets and profits are reflected in the Consolidated Balance Sheets and Statements of Operations.

The balances of the Non-Controlling or Minority Interest holders are as follows as of December 31:

	2006			2005
Beginning Balance	$	399,993		$	574,058
Current Year Addition of Rex Royalties		1,454,634			0
Contributions		0			10,081
Distributions		(874,355	)		(316,978	)
Non-Controlling or Minority Share of Income		520,122			132,832
Ending Balance	$	1,500,394		$	399,993

Investments in Rex Royalties

Douglas Oil & Gas accounted for its 10.0 percent interest in Rex Royalties under the equity method for the year ended December 31, 2005.

Financial information for Rex Royalties is as follows for the Condensed Balance Sheets as of December 31, 2005 and Condensed Statement of Operations for the year ended December 31, 2005:

	2005
Total Assets	$	1,783,214
Total Liabilities	$	318,374
Total Partners’ Equity	$	1,464,840
Total Revenue	$	767,525
Total Expenses	$	131,861
Net Income	$	635,664

The December 31, 2005 consolidated financial statements account for Rex Royalties under the equity method and do not include the effects of consolidation under EITF 04-5. Upon further review and application of EITF 04-5, management determined that Rex Royalties should be consolidated upon the effective date. As such, the financial results of Rex Royalties as of December 31, 2006 are reflected in the consolidated financial statements of the Company.

F-129

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Investments in New Albany

During 2006, the Company acquired an 11.10 percent membership interest in New Albany-Indiana, LLC, a Delaware limited liability company (“New Albany”). New Albany engages in the business of acquiring working interests in leasehold acreage in the Illinois Basin located in Southern Indiana known to contain New Albany Shale formations. In accordance with the terms of New Albany’s limited liability company agreement, the managing member of New Albany, Rex Energy Wabash, LLC, may issue mandatory capital calls to its members for purposes of funding New Albany’s drilling projects. Capital calls are payable by the members of New Albany in accordance with their respective membership interests. As of December 31, 2006, New Albany issued capital calls to the Company in the amount of $1,733,827, all of which were paid by the Company during 2006. The Company accounts for its membership interest in New Albany under the equity method. For the year ended December 31, 2006, the Company recorded a loss of $19,530, to reflect its share of New Albany’s net loss.

Financial information for New Albany is as follows for the Condensed Balance Sheets as of December 31, 2006 and Condensed Statement of Operations for the year ended December 31, 2006:

	2006
Total Assets	$	16,515,664
Total Liabilities	$	1,071,348
Total Partners’ Equity	$	15,444,316
Total Revenue	$	21,230
Total Expenses	$	197,182
Net Loss	$	(175,952	)

Hedging

The Company uses put and call options (collars) and fixed rate swap contracts to manage price risks in connection with the sale of natural gas. The Company accounts for these contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The results of these hedging activities are reflected in the revenue section of the Consolidated Statements of Operations.

The Company has established the fair value of all derivative instruments using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. These values the Company reports in its consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

SFAS No. 133 establishes accounting and reporting standards requiring derivative instruments (including certain derivative instruments embedded in other contracts or agreements) be recorded at fair value and included in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in earnings.

For derivative instruments designated as fair value hedges (in accordance with SFAS No. 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Hedge effectiveness is measured annually based on the relative

F-130

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

changes in fair value between the derivative contract and the hedged item over time. However, the Company’s evaluations are not documented, and as a result, the Company is recording changes on the derivative valuations through earnings.

Royalty Interests in Proved Development Properties

Rex Royalties uses the successful efforts method of accounting for its royalty interest in natural gas properties. The royalty interests in proved developed properties are depleted using the units-of-production method. All royalty interests in development properties relate to proved reserves.

The Company has evaluated the carrying value of its long-lived assets, consisting of royalty interests associated with natural gas producing properties, in order to determine whether the carrying value of such properties should be reduced. Management has determined that no adjustments to the carrying value of the assets are necessary as of December 31, 2006 and 2005.

Oil and Natural Gas Property, Depreciation and Depletion

The Company accounts for its natural gas and oil exploration and production activities under the successful efforts method of accounting.

Proved developed natural gas and oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of natural gas and oil are capitalized.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

The Company accounts for impairment under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field to the unamortized capitalized

F-131

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future natural gas and oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Management determined that properties in 2005 were impaired and recorded expense of $107,119 relating to the impairment.

Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

Natural Gas and Oil Reserve Quantities

The Company’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. The Company’s independent engineering firm, Netherland, Sewell, and Associates, Inc., prepares a reserve and economic evaluation of all the Company’s oil and natural gas properties on a lease-by-lease basis.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The Company’s independent engineering firm adheres to the same guidelines when preparing their reserve reports. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas and oil eventually recovered.

Asset Retirement Obligations

Effective January 1, 2004, the Company adopted SFAS No. 143, “Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS No. 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of the Company’s natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. The asset retirement obligation is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0 percent.

	2006		2005
Beginning Balance	$	330,532	$	302,758
Initial Asset Retirement Obligation Capitalized		0		6,292
Asset Retirement Obligation Accretion Expense		33,686		15,282
Net Additional Asset Retirement Obligation for New and Disposed Wells		6,319		6,200
Total Asset Retirement Obligation	$	370,537	$	330,532

F-132

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Loan Costs

Loan costs consist of gross debt issuance costs that are presented net of accumulated amortization.

New Accounting Pronouncements

On March 30, 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for the Company beginning January 1, 2005, and was applied in estimating the asset retirement obligation at December 31, 2005.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies that use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling, and (3) an aging of exploratory well costs suspended for greater than one year with the number of wells it is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Application of this pronouncement did not have a significant impact on the Company’s financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an

F-133

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. The Company does not expect that adoption of this FASB Staff Position will have a material impact on its results of operations or financial position.

2. CONCENTRATION OF CREDIT RISKS

At times during the year ended December 31, 2006, the Company’s cash balance may have exceeded the Federal Deposit Insurance Corporation insured limit of $100,000. There were no losses incurred due to concentrations.

3. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value of the Company’s long-term debt instruments approximates the fair value as the debt facilities carry a market rate of interest.

The Company estimates the fair value of the participation liability associated with Norguard Insurance Company’s term loan to be $2,141,109 and $740,000 as of December 31, 2006 and 2005, respectively.

The fair value of the asset or (liability) associated with the Company’s hedging instruments is $603,268 and ($143,385) at December 31, 2006 and 2005, respectively. The fair value is based on valuation methodologies of the Company’s counterparties. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

4. COMMITMENTS AND CONTINGENCIES

In March 2004, Douglas Westmoreland purchased from Standard Steel, LLC certain contractual rights associated with various gas purchase contracts relating to 19 natural gas wells. Under the terms of the contracts Douglas Westmoreland buys 100.0 percent of production from these wells from third parties at contracted, fixed prices. The prices it pays range from $1.10 per Mcf to 55.0 percent of the market, price plus a $0.10 per Mcf surcharge. There is no loss on these commitments. The Company has recorded the gross revenue and costs in the Consolidated Statements of Operations. Douglas Westmoreland sells the natural gas extracted from these contract wells to parties unrelated to these natural gas wells and contracts.

Due to the nature of the natural gas and oil business, the Company is exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. It conducts periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort. There were no significant environmental obligations probable or possible as of December 31, 2006.

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company has not experienced any significant environmental liability, and is not aware of any potential environmental issues or claims as of December 31, 2006 and 2005.

In addition to the Asset Retirement Obligation discussed in Note 1, the Company has withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. Such amounts totaling $325,036 are recorded as a liability.

Douglas Westmoreland has posted a $50,000 letter of credit with the Commonwealth of Pennsylvania to secure its drilling and related operations on Keystone State Park in Westmoreland County, Pennsylvania.

5. LINE OF CREDIT

On October 28, 2004, the Company executed a revolving line of credit agreement with Guaranty Bank. The line of credit was to mature on October 28, 2007. Accrued and unpaid interest on the aggregate outstanding line of credit balance was due monthly. The line of credit accrued monthly interest on the floating rate, which is defined at the Company’s base rate plus 1.25 percent. The amount outstanding on the line of credit at

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YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

December 31, 2005 was $3,292,755. All outstanding borrowings under the Guaranty Bank line of credit were repaid by the proceeds of the M&T Bank Term Loan described in Note 6.

6. LONG-TERM DEBT

Term Loan—Norguard

On March 22, 2004, Douglas Westmoreland entered into a loan agreement with Norguard Insurance Company (“Norguard”) in the amount of $2.5 million. In November 2004, in accordance with the term loan agreement, the loan was increased to $3.0 million. The debt proceeds were used by Douglas Westmoreland to finance the acquisition of natural gas properties located in Westmoreland County, Pennsylvania from Standard Steel, LLC and for well and pipeline development. The term loan was secured by all of Douglas Westmoreland’s natural gas properties. The loan earned interest at a fixed-rate of 8.0 percent and matured on June 1, 2009. The loan also included a 20.0 percent contingent interest component applied on excess cash flow. Monthly installments of interest only were payable until the maturity date.

The contingent interest component associated with the loan from Norguard has been accounted for in accordance with AICPA Statement of Position 97-1, “Accounting by Participating Mortgage Loan Borrowers” (“SOP 97-1”)

For the years ended December 31, 2006 and 2005, Douglas Westmoreland recognized a participation liability related to the contingent component associated with the Norguard term loan in accordance with SOP 97-1. This participation liability is reflected in the liability section of the consolidated balance sheets. The Company estimated the fair value of the participation liability to be $740,000 as of December 31, 2005. In 2006, the fair value of the participation liability was estimated to be $2,141,109. The estimated fair value of the participation liability represents a 20.0 percent interest of Douglas Westmoreland’s net present value of future cash inflows derived from its natural gas reserves. The Company utilized a present value factor of 10.0 when estimating the participation liability for the year ended December 31, 2006.

On February 13, 2006, Douglas Westmoreland repaid the outstanding principal amount of the loan with Norguard with the proceeds of the loan with M&T Bank described in Note 6. Norguard retained its 20.0 percent contingent interest in Douglas Westmoreland’s excess cash flows following the February 13, 2006 repayment of the loan. Contingent interest continues to be due in quarterly installments.

Term Loan—M&T Bank

On February 13, 2006, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, entered into a revolving line of credit of up to $10,000,000 with Manufacturers and Traders Trust Company, as agent (the “Agent”) (the “M&T Loan”). The Borrowing Base for the M&T Loan as of December 31, 2006 was $9,500,000. Effective January 12, 2007, the Borrowing Base increased to $10,000,000. Interest on the loan accrues and is payable at a rate per annum equal to the base rate from time to time in effect, plus one percent (1.0%). The base rate is equal to the rate of interest per annum then most recently established by the Agent as its “prime rate”, which rate may not be the lowest rate of interest charged by the Agent to its borrowers. Interest is calculated on unpaid sums actually advanced and outstanding and only for the period from the date or dates of such advances until repayment. Accrued and unpaid interest on aggregate outstanding balances is due monthly and commenced in February 2006. There are no principal payments due monthly. The loan matures on February 13, 2009. The borrowers are jointly and severally liable with respect to borrowings under the M&T Loan.

Each borrower has guaranteed the full and timely payment by the other borrower of each and every obligation and liability of such other borrower to the lenders. In addition, borrowings under the loan are

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

guaranteed, in specified percentages, by Douglas Oil & Gas, Inc., its stockholders, and Lance T. Shaner. The M&T Loan is secured by each of the borrower’s assets and oil and gas producing properties located in the Commonwealth of Pennsylvania and in the states of New Mexico and Texas. Borrowings from the M&T Loan were used to repay all borrowings of Douglas Oil & Gas under a reducing revolving line of credit of up to $50,000,000 with Guaranty Bank, FSB. Borrowings under the M&T Loan were also used to repay the $3,000,000 term loan with Norguard. See Note 5. The outstanding balance on the M&T Term Loan as of December 31, 2006 is $8,941,586 and the interest rate is 9.25 percent.

As of December 31, 2006, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, were not in compliance with the negative covenant in the credit agreement for the M&T Loan which states that the co-borrowers will not permit their tangible net worth, on a combined basis, as of the end of any fiscal year to be less than such amount that is 15% less than the tangible net worth of the co-borrowers as indicated on their audited year end financial statements as of December 31, 2005; provided, however, that commencing on December 31, 2006, and at the end of each fiscal year thereafter, this amount will increase by $500,000. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarters of 2007.

Vehicle Loans

The Company obtained $125,068 in loans to obtain 4 vehicles used in operations. The interest rates on the loans range from 6.24 percent to 8.49 percent. The loans mature in 2009 and 2010. The outstanding balance on these vehicles loans is $96,421 and $111,474 at December 31, 2006 and 2005, respectively.

Future minimum repayments of the Company’s long-term debts are as follows:

2007	$	26,692
2008		28,466
2009		8,972,401
2010		25,318
Thereafter		4,961
Total	$	9,057,838

7. HEDGING ACTIVITIES

The Company’s results of operations and operating cash flows are impacted by changes in market prices for natural gas. To mitigate a portion of the exposure to adverse market changes, the Company entered into natural gas hedges. As of December 31, 2006 and 2005, the Company’s natural gas derivative instruments consisted of fixed rate swap contracts and collars. These instruments allow the Company to predict with greater certainty the effective natural gas price to be received for the Company’s hedged production.

Collars contain a fixed floor price (put) and ceiling price (call). The put options are purchased from the counterparty by the Company’s payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays the Company an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty by the Company’s receipt of a cash premium. If the market price is greater than the call strike price for a calculation period, then the Company pays the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

The Company sells natural gas in the normal course of business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in natural gas sales. The Company enters into derivative instruments such as swap contracts to hedge a portion of its forecasted natural gas sales.

The Company received (incurred) net payments of $739,006 and ($296,535) under these hedges during years ended December 31, 2006 and 2005, respectively. Unrealized gains (losses) associated with these hedges are included in operating revenue and amounted to $746,653 and ($115,385) for the years ended December 31, 2006 and 2005.

Open asset/ (liability) hedging positions at December 31, 2006 consisted of:

Hedge Type	Notional Volume (Mcf)	Period	Put/ Floor Price		Call/ Ceiling Price		Fixed Price		Fair Market Value
Swap Contracts	120,000	1/07–12/07	$	0	$	0	$	7.54	$	67,059
Collars	480,000	1/07–12/07	$	8.00	$	14.65	$	0		735,675
Total Current Portion	600,000								$	802,734
Collars	480,000	1/08–12/08	$	7.00	$	9.35	$	0		(112,146	)
Collars	480,000	1/09–12/09	$	7.00	$	9.35	$	0		(87,320	)
Total Long Term Portion	960,000								$	(199,466	)
Total Financial Instruments	1,560,000								$	603,268

8. RELATED PARTY TRANSACTIONS

Rex Energy Operating Corp., a related party, pays certain administrative costs on behalf of the Company. In turn, Douglas Oil & Gas pays a management fee to Rex Energy Operating Corp. which was $864,622 and $798,079 for 2006 and 2005, respectively.

Douglas Westmoreland pays a monthly management fee to Rex Energy Operating Corp. The management fee expense for 2006 and 2005 was $69,600 and $37,000, respectively.

Rex Royalties pays a monthly management fee to Rex Energy Operating Corp. The management fee expense for 2006 and 2005 was $18,192 and $28,007, respectively.

Douglas Westmoreland had a production payable of $58,038 and $413,734, respectively, due to Rex Royalties as of December 31, 2006 and 2005. Such amounts eliminate in consolidation.

During 2005, Midland advanced $40,000 to Rex Energy Limited Partnership and $10,000 to Rex Royalties.

For each of the years ended December 31, 2006 and 2005, Midland paid a management fee of $24,000 for overhead, accounting and professional services to Douglas Oil and Gas. Such amounts eliminate in consolidation.

As of December 31, 2006, Midland has accrued distributions payable of $102,465 due to its Non-Controlling or Minority partners.

Douglas Oil and Gas had related party receivables due from affiliates recorded for $152,932 and $94,135 at December 31, 2006 and December 31, 2005, respectively. The Company had related party payables due to affiliates of $21,348 and $456,838 at December 31, 2006 and December 31, 2005.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Refer to Note 1 under Principles of Consolidation and Description of Businesses for additional related party information.

9. MAJOR CUSTOMERS

All of the natural gas extracted from Douglas Westmoreland’s wells was sold to Dominion Exploration and Production, Inc. or Dominion Peoples, Inc. in 2006 and 2005.

10. PARTNERSHIP AGREEMENT

All profits and losses of the Company are allocated to the partners in accordance with their percentage interests.

The partners of Douglas Oil & Gas have agreed that allocations and distributions to the limited partners will be made first to Rex Energy Limited Partnership, and then to Douglas Oil & Gas, Inc. based on the priority distribution amounts specified. Other distributions are based on ownership interest percentages. The Company paid $875,612 of priority distributions to Rex Energy Limited Partnership for both 2006 and 2005. Additional excess distributions of $270,000 and $295,530 were paid in 2006 and 2005, respectively.

11. DISPOSALS AND SALE OF OIL AND GAS PROPERTIES AND OTHER ASSETS

In February 2005, the Company sold its remaining interests in the Trenton Black River Project for $550,000. This sale included the Company’s interest in the wells and mineral leasehold acreage. The Company recorded a loss on sale of these oil and gas properties of $186,983 in 2005.

In May 2006, the Company sold a parcel of land in New Jersey for $157,066. The Company recorded a gain on sale of this undeveloped land of $91,416.

12. COSTS INCURRED IN NATURAL GAS ACQUISITION AND DEVELOPMENT ACTIVITIES

Costs incurred by the Company in natural gas and oil property acquisitions and developments are presented below:

	2006		2005
Oil and Natural Gas Property Acquisition Costs	$	6,319	$	12,492
Undeveloped Acreage		121,925		0
Development Costs		2,383,630		1,965,773
Total	$	2,511,874	$	1,978,265

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas and oil.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

13. NATURAL GAS AND OIL CAPITALIZED COSTS

Aggregate capitalized costs for the Company related to natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization is presented below:

	2006			2005
Proved Oil and Natural Gas Properties	$	21,224,544		$	16,352,442
Pipelines and Support Equipment		2,485,505			2,350,119
Wells in Progress		189,293			363,861
Undeveloped Properties		140,443			1,013,645
Total		24,039,785			20,080,067
Less Accumulated Depreciation and Depletion		(8,174,889	)		(5,787,321	)
Total	$	15,864,896		$	14,292,746

14. RESULTS OF NATURAL GAS AND OIL PRODUCING ACTIVITIES

The results of operations for oil and natural gas and oil producing activities (excluding overhead and interest costs) are presented below:

	2006		2005			2004
Revenue
Oil and Natural Gas Sales	$	6,729,846	$	6,961,030		$	3,783,467
Pipeline Revenue		97,199		106,761			137,594
Realized Gain (Loss) on Hedges		739,006		(296,535	)		(250,486	)
Unrealized Gain (Loss) on Hedges		746,653		(115,385	)		(28,000	)
Net Sales		8,312,704		6,655,871			3,642,575
Expenses
Operating Expenses		1,196,643		1,225,946			1,199,850
Production Taxes		109,390		104,044			123,673
Gas Contract Purchases		428,379		402,317			177,515
Impairment Charges on Oil and Gas Properties		0		107,119			3,024,267
Accretion Expense on Asset Retirement Obligation		33,686		15,282			31,037
Depreciation and Depletion		2,123,391		1,053,632			706,664
Total Expenses		3,891,489		2,908,340			5,263,006
Results of Operations for Oil and Natural Gas Producing Activities	$	4,421,215	$	3,747,531		$	(1,620,431	)

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, and other production taxes. In addition, production costs include administrative expenses applicable to support equipment associated with these activities.

Depreciation, depletion, and amortization expense includes those costs associated with capitalization acquisitions and development costs, but does not include the depreciation applicable to support equipment.

There is no provision for income taxes because the Company is a nontaxable entity.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

15. NATURAL GAS AND OIL RESERVE QUANTITIES (UNAUDITED)

The Company’s independent engineers, Netherland, Sewell, and Associates, Inc., have evaluated the Company’s proved oil and natural gas reserves. The Company emphasizes that reserve estimates are inherently imprecise. The Company’s oil and natural gas reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties, and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

Proved oil and natural gas reserves represent the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable accuracy will recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by natural gas and oil and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil and natural gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

Approximately 185,000 barrels of the ending proved reserves for oil equivalents are attributable to the non-controlling interests in Midland and Rex Royalties. Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2006. The reserves are proved developed.

	Oil (bls)		Natural Gas (mcf)		Oil Equivalents
Proved Reserves—Beginning of Period	120,671		11,126,836		1,975,144
Extensions, Discoveries, and Other Additions	0		1,184,960		198,253
Revisions of Previous Estimates	(13,189	)	(311,825	)	(65,193	)
Production	(8,568	)	(760,151	)	(135,987	)
Proved Reserves—End of Period	98,914		11,239,820		1,972,217
Proved developed reserves
December 31, 2005	62,688		8,199,969		1,429,350
December 31, 2006	77,664		7,680,336		1,357,720

16. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

Statement of Financial Accounting Standard No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proven reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0 percent annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

Approximately $3,010,000 of the ending standardized measure of discounted future net cash flows are attributable to the non-controlling interests in Midland and Rex Royalties. The following summary sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by SFAS 69 at December 31, 2006:

Future Cash Inflows	(a) $	71,061,909
Future Production Costs		(20,260,800	)
Future Abandonment Costs		(1,311,625	)
Future Development Costs		(7,634,800	)
Net Future Cash Inflows		41,854,684
Less: Effect of a 10.0% Discount Factor		(21,994,121	)
Standardized Measure of Discounted Future Net Cash Flows	$	19,860,563

(a) Calculated using weighted average prices of $5.54 per mcf of natural gas and $57.03 per barrel of oil.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

Standardized Measure—Beginning of Period	$	41,662,600
Sales of Product—Net of Production Costs		(4,783,839	)
Changes in Prices and Production Costs		(20,049,099	)
Changes in Future Development Costs		(864,334	)
Development Costs Incurred		2,471,743
Plus Extensions, Discoveries, and Other Additions		707,074
Revisions of Previous Quantity Estimates		(1,196,045	)
Changes in Timing and Other		(1,878,240	)
Future Abandonment Costs		(370,537	)
Accretion of Discount		4,161,240
Standardized Measure—End of Period	$	19,860,563

17. LITIGATION

On April 17, 2004, Standard Steel, LLC (“Standard”) filed a complaint in the United States District Court for the Western District of Pennsylvania against Buckeye Energy, Inc. (“Buckeye”) seeking a declaratory judgment declaring the respective rights of Standard and Buckeye relating to three agreements regarding the sale of natural gas from Buckeye’s wells which had been entered into in the early 1980s. The three contracts provide for a fixed price to be paid by Standard to Buckeye for natural gas produced from the subject wells. From inception of the contracts and continuing for over 20 years, Standard paid Buckeye (or Buckeye’s predecessors to

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YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

the contracts) a fixed price for gas which did not vary up or down with the market. In 2001, Buckeye and Standard had entered into amendments to the subject agreement, which added a fixed surcharge to the fixed price paid.

In 2003, Buckeye contended for the first time that the price owed by Standard under the agreements varied with the market price for natural gas. Because the market price for natural gas had risen above the fixed price, Buckeye demanded over $300,000 for gas purchased since 2002 and stated it intended to charge a market price for the future. Standard asked the court to declare that only a fixed price was due for the gas. Buckeye amended its counter-claim to claim over $500,000 for gas sold since 2002 and to seek a declaratory judgment as to future prices. Buckeye also moved for the joinder of Douglas Westmoreland to the action because Standard had conveyed its rights to the gas contracts to the Douglas Westmoreland in March 2004 (See Note 2). Standard did not object to the joinder motion and Douglas Westmoreland was added as a plaintiff in the action.

On January 17, 2005, the parties met in mediation and reached a settlement on the material terms of the dispute. The parties agreed (i) that Standard would pay Buckeye $100,000, (ii) that the price the Douglas Westmoreland would pay Buckeye for natural gas from the wells at issue in the future would be 50.0 percent of market price received by Douglas Westmoreland when it resold the gas (iii) that a $.10 per Mcf surcharge would be payable by Douglas Westmoreland, (iv) that Douglas Westmoreland would take and pay for up to 100,000 Mcf annually from one of the wells, and (v) that the gas that Buckeye would supply to Douglas Westmoreland would be of a merchantable quantity. The agreement reached at the settlement meeting was not reduced to writing. On January 20, 2005, counsel for the plaintiffs, with the full authorization of Buckeye’s counsel, informed the court that the parties had settled. On January 21, 2005, the court entered an order stating that the case had been settled and that the case would be administratively closed pending the filing of a notice of dismissal. On February 4, 2005, new counsel to Buckeye informed the plaintiff’s counsel that a settlement did not exist and that Buckeye intended to proceed with the litigation. On February 11, 2005, Buckeye filed a motion to reopen the case. On February 25, 2005, Douglas Westmoreland and Standard filed a motion to enforce the oral settlement agreement entered into on January 17, 2005.

On February 25, 2005, Buckeye filed a motion in opposition of enforcement of the settlement contending that it had not entered into a definitive oral settlement agreement at the mediation on January 17, 2005, and in the alternative, in the event the court determined that it had done so, any such agreement was required to be in writing. On July 27, 2005, the court held an evidentiary hearing on the motions. On September 29, 2005, the court issued an order finding that the parties entered into an oral settlement on January 17, 2005. On October 27, 2005, Buckeye appealed the order to the United States Court of Appeals for the Third Circuit. On December 16, 2005, the parties entered into a written settlement agreement that amended the oral settlement agreement to, among other things, provide that Douglas Westmoreland would pay Buckeye 55.0 percent of the gross price paid to Douglas Westmoreland when it resells the gas. On January 11, 2006, the Court of Appeals for the Third Circuit dismissed Buckeye’s appeal due to the settlement between the parties, thus resolving the matter. There is no recorded liability related to this matter.

On November 23, 2004, Dale Campbell (“Campbell”) filed an Amended Complaint in the Court of Common Pleas of Westmoreland County, Pennsylvania against Douglas Westmoreland and Standard, seeking a declaratory judgment that Douglas Westmoreland is required to pay him for natural gas produced at various wells at rates allegedly agreed to under a written agreement and oral agreement between the parties, and account for monies paid to Campbell during the duration of their contractual relationship.

The well contracts, which are the subject of this lawsuit, were purchased by Douglas Westmoreland in the transaction with Standard. Douglas Westmoreland filed an answer on March 4, 2005, denying the material

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DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

allegations of Campbell’s compliant and asserting that Campbell’s claims are barred or otherwise fail because, among other reasons, the claims are untimely and because Campbell has already been paid in full. As of December 31, 2006, Campbell had not taken any further action to prosecute the claims asserted in the lawsuit. Douglas Westmoreland believes that Campbell had postponed any further action in the lawsuit pending resolution of the litigation with Buckeye described above. In the event Campbell takes any action in this lawsuit, Douglas Westmoreland intends to vigorously defend the claims that have been asserted against it in this action and to seek a dismissal of the action for failure to prosecute. Douglas Westmoreland believes that the likelihood of an unfavorable outcome of this matter is remote.

18. SUBSEQUENT EVENTS

Through February 2007, New Albany issued two mandatory capital calls to its members totaling $2,120,073. The Company’s portion of these capital calls is $235,325. In order to remain a member in New Albany, the Company must fund the capital calls, and as such, the Company intends to contribute the amounts required in the capital call.

As of December 31, 2006, Douglas Oil & Gas and Douglas Westmoreland, as co-borrowers, were not in compliance with the negative covenant in the credit agreement for the M&T Loan which states that the co-borrowers will not permit their tangible net worth, on a combined basis, as of the end of any fiscal year to be less than such amount that is 15% less than the tangible net worth of the co-borrowers as indicated on their audited year end financial statements as of December 31, 2005; provided, however, that commencing on December 31, 2006, and at the end of each fiscal year thereafter, this amount will increase by $500,000. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarters of 2007.

19. CONSOLIDATED FINANCIAL STATEMENTS

As described in Note 1, the consolidated financial statements include Douglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, and Rex Energy Royalties Limited Partnership. The following information presents consolidating financial statements, which include individual company information and the eliminations necessary to consolidate Douglas Oil & Gas Limited Partnership.

F-144

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING BALANCE SHEET

December 31, 2006

	Douglas Oil & Gas			Douglas Westmoreland			Midland Exploration			Rex Royalties			Eliminations			Consolidated Balance
ASSETS
CURRENT ASSETS
Cash	$	0		$	0		$	64,245		$	1,482		$	0		$	65,727
Production Receivable—Net of Allowance for Doubtful Accounts of $0 for 2006		798,893			664,953			80,231			58,038			(58,038	)		1,544,077
Joint Interest Billing Receivables		44,612			0			0			0			0			44,612
Other Receivables		0			7,733			0			0			0			7,733
Financial Instruments—Current Portion		401,367			401,367			0			0			0			802,734
Related Party Receivable		675,268			0			0			8,277			(507,474	)		176,071
Prepaid Expenses		95,867			0			2,088			0			0			97,955
TOTAL CURRENT ASSETS		2,016,007			1,074,053			146,564			67,797			(565,512	)		2,738,909
OIL AND GAS PROPERTY AND EQUIPMENT
Undeveloped Properties		140,443			0			0			0			0			140,443
Wells In Progress		189,293			0			0			0			0			189,293
Proved Developed Oil and Natural Gas Properties		13,235,006			5,796,901			692,637			1,500,000			0			21,224,544
Pipelines		1,530,969			233,470			0			0			0			1,764,439
Transportation Vehicles and Other Equipment		680,962			40,104			0			0			0			721,066
Total Oil and Gas Property and Equipment		15,776,673			6,070,475			692,637			1,500,000			0			24,039,785
Less: Accumulated Depreciation, Depletion, and Amortization		(6,520,122	)		(1,024,040	)		(372,565	)		(258,162	)		0			(8,174,889	)
NET OIL AND GAS PROPERTY AND EQUIPMENT		9,256,551			5,046,435			320,072			1,241,838			0			15,864,896
OTHER ASSETS
Investments in Related Parties		1,287,415			0			0			0			426,882			1,714,297
Financial Instruments—Long Term Portion		0			0			0			0			0			0
Deposits and Other Assets		55,000			0			0			0			0			55,000
Loan Costs—Net of Accumulated Amortization		102,340			0			0			0			0			102,340
TOTAL OTHER ASSETS		1,444,755			0			0			0			426,882			1,871,637
TOTAL ASSETS	$	12,717,313		$	6,120,488		$	466,636		$	1,309,635		$	(138,630	)	$	20,475,442
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES
Line of Credit	$	0		$	0		$	0		$	0		$	0		$	0
Accounts Payable		317,853			313,314			104,193			0			0			735,360
Production Payable		13,754			39,779			0			0			0			53,533
Current Portion—Vehicle Loans		21,656			5,036			0			0			0			26,692
Drilling Advances		0			0			0			0			0			0
Accrued Expenses		75,590			73,100			2,535			0			0			151,225
Accrued Distributions—Related Party		0			0			23,139			0			(23,139	)		0
Accrued Distributions		0			0			102,465			0			0			102,465
Related Party Payable		35,705			530,467			20,688			0			(542,373	)		44,487
TOTAL CURRENT LIABILITIES		464,558			961,696			253,020			0			(565,512	)		1,113,762
OTHER LIABILITIES
Term Loans	$	5,941,586			3,000,000			0			0			0			8,941,586
Discount on Term Loan—Norguard—Net of Amortization		0			0			0			0			0			0
Participation Liability		0			2,141,109			0			0			0			2,141,109
Asset Retirement Obligation		229,677			132,485			8,375			0			0			370,537
Other Deposits		322,046			0			0			0			0			322,046
Vehicle Loans		74,765			14,796			0			0			0			89,561
Financial Instrument Payable		99,733			99,733			0			0			0			199,466
TOTAL OTHER LIABILITIES		6,667,807			5,388,123			8,375			0			0			12,064,305
TOTAL LIABILITIES		7,132,365			6,349,819			261,395			0			(565,512	)		13,178,067
CUMULATIVE NON-CONTROLLING OR MINORITY
INTEREST IN SUBSIDIARIES		0			(2,721	)		203,686			1,309,635			(10,206	)		1,500,394
COMMITMENTS AND CONTINGENCIES (Note 4)
PARTNERS’ EQUITY (DEFICIT)		5,584,948			(226,610	)		1,555			0			437,088			5,796,981
TOTAL LIABILITIES, NON-CONTROLLING OR MINORITY INTERESTS AND PARTNERS’ EQUITY	$	12,717,313		$	6,120,488		$	466,636		$	1,309,635		$	(138,630	)	$	20,475,442

F-145

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING BALANCE SHEET

December 31, 2005

	Douglas Oil & Gas			Douglas Westmoreland			Midland Exploration			Eliminations			Consolidated Balance
ASSETS
CURRENT ASSETS
Cash	$	606,373		$	210,242		$	18,778		$	0		$	835,393
Production Receivable—Net of Allowance for Doubtful Accounts of $2,347 for 2005		801,939			493,073			73,434			0			1,368,446
Joint Interest Billing Receivables		151,009			0			0			0			151,009
Related Party Receivable		53,661			0			69,374			(28,900	)		94,135
Prepaid Expenses		27,954			7,403			7,651			0			43,008
TOTAL CURRENT ASSETS		1,640,936			710,718			169,237			(28,900	)		2,491,991
OIL AND GAS PROPERTY AND EQUIPMENT
Undeveloped Properties		1,013,645			0			0			0			1,013,645
Wells In Progress		362,076			0			1,785			0			363,861
Proved Developed Oil and Natural Gas Properties		11,262,655			4,430,617			659,170			0			16,352,442
Pipelines		1,509,601			113,107			0			0			1,622,708
Transportation Vehicles and Other Equipment		687,307			40,104			0			0			727,411
Total Oil and Gas Property and Equipment		14,835,284			4,583,828			660,955			0			20,080,067
Less: Accumulated Depreciation, Depletion, and Amortization		(5,122,830	)		(453,807	)		(210,684	)		0			(5,787,321	)
NET OIL AND GAS PROPERTY AND EQUIPMENT		9,712,454			4,130,021			450,271			0			14,292,746
OTHER ASSETS
Investments in Related Parties		27,668			0			0			(17,456	)		10,212
Deposits and Other Assets		20,400			0			0			0			20,400
Loan Costs—Net of Accumulated Amortization		57,057			0			0			0			57,057
TOTAL OTHER ASSETS		105,125			0			0			(17,456	)		87,669
TOTAL ASSETS	$	11,458,515		$	4,840,739		$	619,508		$	(46,356	)	$	16,872,406
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES
Line of Credit	$	3,292,755		$	0		$	0		$	0		$	3,292,755
Accounts Payable		178,130			56,329			7,829			0			242,288
Production Payable		887,316			58,530			0			0			945,846
Current Portion—Vehicle Loans		30,000			3,422			0			0			33,422
Drilling Advances		75,060			0			0			0			75,060
Accrued Expenses		70,095			72,648			0			0			142,743
Accrued Distributions—Related Party		0			0			28,900			(28,900	)		0
Accrued Distributions		0			0			127,979			0			127,979
Related Party Payable		42,119			981,988			0			(567,269	)		456,838
TOTAL CURRENT LIABILITIES		4,575,475			1,172,917			164,708			(596,169	)		5,316,931
OTHER LIABILITIES
Term Loan—Norguard		0			3,000,000			0			0			3,000,000
Discount on Term Loan—Norguard—Net of Amortization		0			(165,746	)		0			0			(165,746	)
Participation Liability		0			740,000			0			0			740,000
Asset Retirement Obligation		206,381			116,538			7,613			0			330,532
Other Deposits		325,036			0			0			0			325,036
Vehicle Loans		81,474			19,832			0			0			101,306
Financial Instrument Payable		143,385			0			0			0			143,385
TOTAL OTHER LIABILITIES		756,276			3,710,624			7,613			0			4,474,513
TOTAL LIABILITIES		5,331,751			4,883,541			172,321			(596,169	)		9,791,444
CUMULATIVE NON-CONTROLLING OR MINORITY INTEREST IN SUBSIDIARIES		0			(856	)		400,849			0			399,993
COMMITMENTS AND CONTINGENCIES (Note 4)
PARTNERS’ EQUITY (DEFICIT)		6,126,764			(41,946	)		46,338			549,813			6,680,969
TOTAL LIABILITIES, NON-CONTROLLING OR MINORITY INTERESTS AND PARTNERS’ EQUITY	$	11,458,515		$	4,840,739		$	619,508		$	(46,356	)	$	16,872,406

F-146

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2006

	Douglas Oil & Gas			Douglas Westmoreland			Midland Exploration		Rex Royalties		Eliminations			Consolidated Balance
OPERATING REVENUE
Oil and Natural Gas Sales	$	2,926,180		$	2,715,674		$	401,754	$	686,238	$	0		$	6,729,846
Pipeline Revenue		97,199			0			0		0		0			97,199
Realized Gain on Hedges		201,631			537,375			0		0		0			739,006
Unrealized Gain on Hedges		445,019			301,634			0		0		0			746,653
Well Service Charges and Other Fees		26,353			0			0		0		(24,000	)		2,353
TOTAL OPERATING REVENUE		3,696,382			3,554,683		$	401,754	$	686,238		(24,000	)	$	8,315,057
OPERATING EXPENSES
Operating Expenses		754,598			336,939			86,914		18,192		0			1,196,643
Production Taxes		68,863			0			40,527		0		0			109,390
Gas Contract Purchases		0			428,379			0		0		0			428,379
General and Administrative		513,843			149,223			60,305		64,929		(24,000	)		764,300
Accretion Expense		20,880			12,044			762		0		0			33,686
Impairment Charge on Oil and Gas Properties		0			0			0		0		0			0
Depreciation, Depletion, and Amortization		1,548,642			570,499			161,881		123,249		0			2,404,271
TOTAL OPERATING EXPENSES		2,906,826			1,497,084			350,389		206,370		(24,000	)		4,936,669
INCOME (LOSS) FROM OPERATIONS		789,556			2,057,599			51,365		479,868		0			3,378,388
OTHER INCOME (EXPENSE)
Interest Income		4,589			15,402			0		0		0			19,991
Interest Expense		(458,652	)		(2,259,530	)		0		0		0			(2,718,182	)
Gain (Loss) on Sale of Oil and Gas Properties		91,416			0			0		0		0			91,416
Other Income		51,038			0			0		0		(40,905	)		10,133
TOTAL OTHER EXPENSE		(311,609	)		(2,244,128	)		0		0		(40,905	)		(2,596,642	)
TOTAL INCOME (LOSS) BEFORE MINORITY INTEREST		477,947			(186,529	)		51,365		479,868		(40,905	)		781,746
NON-CONTROLLING OR MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES		0			(1,865	)		42,119		479,868		0			520,122
NET INCOME (LOSS)	$	477,947		$	(184,664	)	$	9,246	$	0	$	(40,905	)	$	261,624

F-147

DOUGLAS OIL & GAS LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2005

	Douglas Oil & Gas			Douglas Westmoreland			Midland Exploration		Eliminations			Consolidated Balance
OPERATING REVENUE
Oil and Natural Gas Sales	$	3,669,512		$	2,818,821		$	472,697		0		$	6,961,030
Pipeline Revenue		106,761			0			0		0			106,761
Realized Loss on Hedges		(197,973	)		(98,562	)		0		0			(296,535	)
Unrealized Loss on Hedges		(115,385	)		0			0		0			(115,385	)
Well Service Charges and Other Fees		101,280			0			0		(24,000	)		77,280
TOTAL OPERATING REVENUE		3,564,195			2,720,259		$	472,697		(24,000	)	$	6,733,151
OPERATING EXPENSES
Operating Expenses		875,439			327,833			22,674		0			1,225,946
Production Taxes		68,138			0			35,906		0			104,044
Gas Contract Purchases		0			402,317			0		0			402,317
General and Administrative		474,306			57,358			34,234		(24,000	)		541,898
Accretion Expense		6,971			6,990			1,321		0			15,282
Impairment Charge on Oil and Gas Properties		0			0			107,119		0			107,119
Depreciation, Depletion, and Amortization		627,288			350,000			115,000		0			1,092,288
TOTAL OPERATING EXPENSES		2,052,142			1,144,498			316,254		(24,000	)		3,488,894
INCOME (LOSS) FROM OPERATIONS		1,512,053			1,575,761			156,443		0			3,244,257
OTHER INCOME (EXPENSE)
Interest Income		30,431			18,490			0		0			48,921
Interest Expense		(269,648	)		(1,073,650	)		0		0			(1,343,298	)
Gain (Loss) on Sale of Oil and Gas Properties		(186,983	)		0			0		0			(186,983	)
Other Income		235,990			0			0		(29,000	)		206,990
TOTAL OTHER EXPENSE		(190,210	)		(1,055,160	)		0		(29,000	)		(1,274,370	)
TOTAL INCOME (LOSS) BEFORE MINORITY INTEREST		1,321,843			520,601			156,443		(29,000	)		1,969,887
NON-CONTROLLING OR MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES		0			5,206			127,626		0			132,832
NET INCOME (LOSS)	$	1,321,843		$	515,395		$	28,817	$	(29,000	)	$	1,837,055

F-148

Douglas Westmoreland Limited Partnership

F-149

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Douglas Westmoreland Limited Partnership

State College, Pennsylvania

We have audited the accompanying balance sheets of Douglas Westmoreland Limited Partnership as of December 31, 2006 and 2005 and the related statements of operations, changes in partners’ equity and cash flows for the years then ended and for the period from inception to December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Douglas Westmoreland Limited Partnership as of December 31, 2006 and 2005, and the results of its operations and its cash flows for the years then ended and for the period from inception to December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

Pittsburgh, Pennsylvania

March 15, 2007

F-150

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

BALANCE SHEETS

	December 31,
	2006			2005
ASSETS
CURRENT ASSETS
Cash	$	0		$	210,242
Production Receivable		664,953			482,787
Other Receivables		7,733			10,286
Financial Instrument—Current Portion		401,367			0
Prepaid Expenses		0			7,403
TOTAL CURRENT ASSETS		1,074,053			710,718
PROPERTY AND EQUIPMENT
Proved Developed Natural Gas Properties		5,796,901			4,430,617
Vehicles		40,104			40,104
Pipelines		233,470			113,107
Total Property and Equipment		6,070,475			4,583,828
Less: Accumulated Depreciation, Depletion, and Amortization		(1,024,040	)		(453,807	)
NET BOOK VALUE		5,046,435			4,130,021
TOTAL ASSETS	$	6,120,488		$	4,840,739
LIABILITIES AND PARTNERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts Payable	$	313,314		$	56,329
Production Payable		39,779			58,530
Amounts Payable to Related Parties		530,467			981,988
Vehicle Loan Payable—Current Portion		5,036			3,422
Accrued Liabilities		73,100			72,648
TOTAL CURRENT LIABILITIES		961,696			1,172,917
OTHER LIABILITIES
Long-Term Debt		3,000,000			3,000,000
Vehicle Loan—Long-Term Portion		14,796			19,832
Discount on Long-Term Debt—Net of Amortization		0			(165,746	)
Participation Liability		2,141,109			740,000
Financial Instrument—Long Term Portion		99,733			0
Asset Retirement Obligation		132,485			116,538
TOTAL OTHER LIABILITIES		5,388,123			3,710,624
TOTAL LIABILITIES		6,349,819			4,883,541
COMMITMENTS AND CONTINGENCIES (NOTE 6)
PARTNERS’ EQUITY (DEFICIT)		(229,331	)		(42,802	)
TOTAL LIABILITIES AND PARTNERS’ EQUITY (DEFICIT)	$	6,120,488		$	4,840,739

SEE ACCOMPANYING NOTES.

F-151

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

STATEMENTS OF OPERATIONS

	Year Ended December 31,						Period From Inception to December 31,
	2006			2005			2004
OPERATING REVENUE
Natural Gas Sales	$	2,715,674		$	2,818,821		$	932,482
Realized Gains (Losses) on Hedges		537,375			(98,562	)		(32,074	)
Unrealized Gain (Loss) on Hedges		301,634			0			0
TOTAL OPERATING REVENUE		3,554,683			2,720,259			900,408
OPERATING EXPENSES
Production Expenses		336,939			327,833			169,606
Gas Contract Purchases		428,379			402,317			177,515
Accretion Expense on Asset Retirement Obligation		12,044			6,990			12,881
General and Administrative		149,223			57,358			33,083
Depreciation, Depletion, and Amortization		570,499			350,000			103,807
TOTAL OPERATING EXPENSES		1,497,084			1,144,498			496,892
INCOME FROM OPERATIONS		2,057,599			1,575,761			403,516
OTHER INCOME (EXPENSE)
Interest and Other Income		15,402			18,490			0
Interest Expense		(2,259,530	)		(1,073,650	)		(364,347	)
TOTAL OTHER INCOME (EXPENSE)		(2,244,128	)		(1,055,160	)		(364,347	)
NET (LOSS) INCOME	$	(186,529	)	$	520,601		$	39,169

SEE ACCOMPANYING NOTES.

F-152

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

STATEMENTS OF CHANGES IN PARTNERS’ EQUITY (DEFICIT)

YEARS ENDED DECEMBER 31, 2006, 2005, AND PERIOD FROM INCEPTION TO

December 31, 2004

	Partners’ Equity (Deficit)
BEGINNING BALANCE—January 1, 2004	$	0
CAPITAL CONTRIBUTIONS		540,000
DISTRIBUTIONS TO PARTNERS		(194,814	)
NET INCOME		39,169
ENDING BALANCE—December 31, 2004	$	384,355
CAPITAL CONTRIBUTIONS		336,081
DISTRIBUTIONS TO PARTNERS		(1,283,839	)
NET INCOME		520,601
ENDING BALANCE—December 31, 2005	$	(42,802	)
CAPITAL CONTRIBUTIONS		0
DISTRIBUTIONS TO PARTNERS		0
NET LOSS		(186,529	)
ENDING BALANCE—December 31, 2006	$	(229,331	)

SEE ACCOMPANYING NOTES.

F-153

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

STATEMENTS OF CASH FLOWS

	Year Ended December 31,						Period From Inception to December 31,
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(186,529	)	$	520,601		$	39,169
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation, Depletion, and Amortization		570,499			350,000			103,807
Net Amortization of Participation Liability		1,566,855			443,634			130,620
Accretion Expense on Asset Retirement Obligation		12,044			6,990			12,881
Unrealized (Gain) Loss on Hedges		(301,634	)		176			(176	)
(Increase) Decrease in
Production Receivable		(182,166	)		(224,084	)		(258,703	)
Other Receivables		2,553			0			0
Prepaid Expenses		7,403			0			0
Increase (Decrease) in
Accounts Payable		238,234			(410,575	)		466,904
Amounts Payable to Related Parties		115,748			354,277			118,972
Accrued Liabilities		452			10,968			61,680
NET CASH PROVIDED BY OPERATING ACTIVITIES		1,843,459			1,051,987			675,154
CASH FLOWS USED BY INVESTING ACTIVITIES
Development of Natural Gas Properties and Related Equipment		(1,483,010	)		(673,486	)		(3,808,110	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayment of Vehicle Loan		(3,422	)		0			0
Proceeds from M&T Line of Credit		3,000,000			0			0
Proceeds from Long-Term Debt		0			0			3,000,000
Repayment of long-term debt to Norguard		(3,000,000	)		0			0
Capital Contributions		0			336,081			540,000
Distributions to Partners		(567,269	)		(716,570	)		(194,814	)
NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES		(570,691	)		(380,489	)		3,345,186
NET INCREASE (DECREASE) IN CASH		(210,242	)		(1,988	)		212,230
CASH—BEGINNING		210,242			212,230			0
CASH—ENDING	$	0		$	210,242		$	212,230
SUPPLEMENTAL DISCLOSURES
Cash Paid for Interest	$	692,675		$	612,013		$	192,449
NON-CASH ACTIVITIES
Distribution to General Partner Recorded as Payable	$	0		$	567,269		$	0

SEE ACCOMPANYING NOTES.

F-154

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Formation and Description of Business

Douglas Westmoreland Limited Partnership (“Douglas Westmoreland” or “Company”) was formed as a Delaware limited partnership on March 10, 2004 to own and operate natural gas properties. The general partner is Rex Energy, LLC (1.0 percent). The remaining 99.0 percent limited partnership interest is owned by Douglas Oil & Gas Limited Partnership. The Company engages in the exploration, acquisition, management, leasing, development, and extraction of natural gas from underground reservoirs. The Company operates and has a 100.0 percent working interest in approximately 49 natural gas wells located in Westmoreland County, Pennsylvania.

Basis of Presentation

These financial statements present the financial position, results of operations, and changes in equity and cash flows for Douglas Westmoreland only. Douglas Westmoreland financial statements are required to be included with the consolidated financial statements of their general partner, Douglas Oil & Gas Limited Partnership, under the guidance of EITF 04-5—Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights. The Consolidated Financial Statements of Douglas Oil & Gas Limited Partnership are issued separately from these financial statements.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, commodity collars, accounts receivable, accounts payable, long-term debt, and a participation liability associated with the long-term debt.

Revenue Recognition

Natural gas revenue is recognized when the natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of gas purchased (although there are provisions for challenging these measurements if we believe the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our natural gas production is at our applicable field gathering system; therefore, we do not incur transportation costs related to our sales of natural gas production. The Company does not currently participate in any gas-balancing arrangements. Douglas Westmoreland uses the allowance method to account for uncollectible accounts receivable. At December 31, 2006 and 2005, there was no allowance for doubtful accounts.

F-155

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

Hedging

The Company uses commodity collars and fixed price swaps to manage price risk in connection with the sale of natural gas and accounts for those contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Results of natural gas derivative transactions are reflected in natural gas sales.

The Company has established the fair value of all derivative instruments using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. The values it reports in its financial statements change as these estimates are revised to reflect actual results, changes in market conditions, or other factors.

SFAS No. 133 establishes accounting and reporting standards requiring derivative instruments (including certain derivative instruments embedded in other contracts or agreements) be recorded at fair value and included in the Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in earnings. For derivative instruments designated as fair value hedges (in accordance with SFAS No. 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Hedge effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are also recognized currently in earnings.

Income Taxes

The Company is treated as a partnership for federal and state income tax purposes. Accordingly, income taxes are not reflected in the financial statements because the resulting profit or loss is included in the income tax returns of the individual partners.

Natural Gas Properties Depreciation, Depletion, and Amortization

The Company accounts for its natural gas exploration and production activities under the successful efforts method of accounting.

Proved developed natural gas property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas properties. Natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved

F-156

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of natural gas, are capitalized.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

The Company accounts for impairment under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Management determined that no adjustments to the unamortized capitalized cost were necessary as of December 31, 2006 and 2005.

Upon the sale or retirement of a proved natural gas property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain. There were no sales of natural gas properties in 2006 and 2005.

Accounting Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Accordingly, actual results could differ from those estimates. Among the more sensitive of the estimates involves determining the proved reserves from which depletion expense is calculated, calculating the plugging liability, and determining the future net cash flows from which asset impairment, if any, is ascertained.

F-157

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

Natural Gas and Oil Reserve Quantities

The Company’s estimate of proved reserves is based on the quantities of natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell, and Associates, Inc. prepare a reserve and economic evaluation of all the Company’s properties on a lease-by-lease basis.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of the Company’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas eventually recovered.

New Accounting Pronouncements

On March 30, 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for the Company beginning January 1, 2005, and was applied in estimating the asset retirement obligation at December 31, 2005.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies that use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling, and (3) an aging of exploratory well costs suspended for greater than one year with the number of wells it is related to. Further, the disclosures should describe the activities undertaken to evaluate the

F-158

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Application of this pronouncement did not have a significant impact on the Company’s financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the

F-159

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. The Company does not expect that adoption of this FASB Staff Position will have a material impact on its results of operations or financial position.

Reclassification

The prior year financial statements have been reclassified to conform to current year presentation.

2. CONCENTRATION OF CREDIT RISKS

At times during the year ended December 31, 2006, the Company’s cash balance may have exceeded the Federal Deposit Insurance Corporation insured limit of $100,000. There were no losses incurred due to concentrations.

3. ASSET RETIREMENT OBLIGATIONS

Effective March 10, 2004, the Company adopted SFAS No. 143 “Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS No. 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For natural gas properties, this is the period in which the natural gas well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of the Company’s natural gas properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas well is sold, at which time the liability is reversed. The asset retirement obligation is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0 percent.

A summary of the asset retirement obligation at December 31 is as follows:

	2006		2005
Beginning Balance	$	116,538	$	103,043
Additional Asset Retirement Obligation Capitalized		3,903		6,505
Asset Retirement Obligation Accretion Expense		12,044		6,990
Total	$	132,485	$	116,538

4. LONG-TERM DEBT

Term Loans

On February 26, 2004, the Company, entered into a purchase agreement with Standard Steel, LLC (“Standard”) to acquire all the rights, title, and interests of Standard’s pipelines, natural gas wells, leases, and gas purchase contracts located in Westmoreland County, for a total purchase price of $4.0 million. The acquisition was completed on March 22, 2004. A portion of the purchase price was paid through the sale of royalty interests in the properties acquired by the Company from Standard to Rex Energy Royalties Limited Partnership (“Rex Royalties”) The Company capitalized $2.5 million of the acquisition and Rex Royalties capitalized $1.5 million. On March 22, 2004, the Company entered into a loan agreement with Norguard Insurance Company (“Norguard”) for $2.5 million. In November 2004, in accordance with the term loan agreement, the loan was

F-160

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

increased to $3.0 million. The debt proceeds were used solely to finance the purchase agreement with Standard Steel and for well and pipeline development. The term loan was secured by all of the Company’s natural gas properties. The loan earned interest at a fixed-rate of 8.0 percent and was to mature on June 1, 2009. The loan also included a 20.0 percent contingent interest component applied on excess cash flow. Monthly installments of interest only were payable until the maturity date. Contingent interest was due in quarterly installments.

On February 13, 2006, the Company and Douglas Oil & Gas Limited Partnership, as co-borrowers, entered into a revolving line of credit of up to $10,000,000 with Manufacturers and Traders Trust Company, as agent (the “Agent”) (the “M&T Loan”). The Borrowing Base, as of December 31, 2006 was $9,500,000. Effective January 12, 2007, the Borrowing Base increased to $10,000,000. Interest on the loan accrues and is payable at a rate per annum equal to the base rate from time to time in effect, plus one percent (1.0%). The base rate is equal to the rate of interest per annum then most recently established by the Agent as its “prime rate”, which rate may not be the lowest rate of interest charged by the Agent to its borrowers. Interest is calculated on unpaid sums actually advanced and outstanding and only for the period from the date or dates of such advances until repayment. Accrued and unpaid interest on aggregate outstanding balances is due monthly and commenced in February 2006. There are no principal payments due monthly. The loan matures on February 13, 2009. The borrowers are jointly and severally liable with respect to borrowings under the M&T Loan. The balance outstanding on the M&T Loan was $3,000,000 at December 31, 2006.

Each borrower has guaranteed the full and timely payment by the other borrower of each and every obligation and liability of such other borrower to the lenders. In addition, borrowings under the loan are guaranteed, in specified percentages, by Douglas Oil & Gas, Inc., its stockholders, and Lance T. Shaner. The M&T Loan is secured by each of the borrowers’ assets and oil and gas producing properties located in the Commonwealth of Pennsylvania and in the states of New Mexico and Texas. Borrowings from the M&T Loan were used to repay all borrowings of Douglas Oil & Gas Limited Partnership under a revolving line of credit with Guaranty Bank, FSB. Borrowings under the M&T Loan were also used to repay the $3,000,000 term loan with Norguard.

As of December 31, 2006, the Company and Douglas Oil & Gas Limited Partnership, as co-borrowers, were not in compliance with the Tangible Net Worth covenant in the term loan agreement requiring that 85.0 percent of December 31, 2005 Tangible Net Worth, as defined in the term loan agreement, increase by $500,000. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarter of 2007.

The contingent interest component assigned to the loan agreement with Norguard Insurance Company was accounted for in accordance with AICPA Statement of Position 97-1, “Accounting by Participating Mortgage Loan Borrowers” (“SOP 97-1”).

For the years ended December 31, 2006 and 2005, the Company recognized a participation liability in accordance with SOP 97-1 related to the contingent component associated with Norguard term loan. This participation liability is reflected in the liability section of the Balance Sheets. The Company estimated the fair value of the participation liability to be $740,000 as of December 31, 2005. In 2006, the fair value of the participation liability was estimated to be $2,141,109. The estimated fair value of the participation liability represents a 20.0 percent interest of the Company’s net present value of future cash inflows derived from their natural gas reserves. The Company utilized a present value factor of 10.0 percent when estimating the participation liability for the year ended December 31, 2006.

F-161

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

Following the February 13, 2006 refinancing events, Norguard retained the 20.0 percent contingent interest in the Company’s excess cash flows. Contingent interest continues to be due in quarterly installments.

Interest expense in 2006 and 2005 consists of the following:

	2006		2005
Amortization of Discount and Increase of Participation Liability	$	1,566,855	$	443,634
Interest at 8% on Line of Credit and Norguard Term Loan		240,000		240,000
Contingent Interest Paid on Norguard Term Loan		449,453		350,482
Interest on Vehicle Loan and Other		3,222		39,534
Total Interest	$	2,259,530	$	1,073,650

The Company also has a vehicle loan at 9.15 percent, with monthly payments of principal and interest of $554, maturing in June 2010.

Total loan maturities over the next five years are as follows:

2007	$	5,036
2008		5,517
2009		3,006,044
2010		3,235
Total	$	3,019,832

5. PARTNERSHIP AGREEMENT

The partners of the Company have agreed that allocations of profits and losses be distributed to the partners in accordance with their percentage interests in the Company. Distributions to partners are allocated among partners in accordance with their respective economic interests at the date of distribution. Distributions of net cash flow, if any, are distributed first, in an amount equal to the excess of such partner’s tax liability for such year over the amount distributed to such partner with respect to such year, and second, in accordance with the partner’s percentage interest. Other distributions are based on percentage interests. The Company distributed $6,303 to the general partner and an aggregate of $1,082,722 to the limited partners during the year ended December 31, 2005. No distributions were made during the year ended December 31, 2006.

6. COMMITMENTS AND CONTINGENCIES

In accordance with the purchase agreement with Standard, the Company was assigned the rights of various gas purchase contracts associated with nineteen natural gas wells. Under the terms of these contracts, the Company buys 100.0 percent of production of these wells from third parties at contracted, fixed prices. The prices the Company pays range from $1.10 per Mcf to 55.0 percent of the market price, plus a $0.10 per Mcf surcharge. There is no loss on these commitments. The Company has recorded the gross revenue and costs in the Statements of Operations. The Company then sells the natural gas extracted from these contract wells to parties unrelated to the natural gas wells and the third-party contracts.

Due to the nature of the natural gas business, the Company is exposed to possible environmental risks. It has implemented various policies and procedures to avoid environmental contamination and risks from

F-162

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

environmental contamination. It conducts periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other factors, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort. Management knows of no significant probable or possible environmental contingent liabilities.

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company has not experienced any significant environmental liability, and is not aware of any potential environmental issues or claims as of December 31, 2006.

The Company has a $50,000 letter of credit posted with the Commonwealth of Pennsylvania to secure its drilling operations.

7. HEDGING ACTIVITIES

The Company’s results of operations and operating cash flows are impacted by changes in market prices for natural gas. To mitigate a portion of the exposure to adverse market changes, the general partner cause the Company to enter into natural gas hedges. As of December 31, 2006 and 2005, the Company’s natural gas derivative instruments consisted of collars and swap contracts. These instruments allow the Company to predict with greater certainty the effective natural gas price to be received for its hedged production.

Collars contain a fixed floor price (put) and ceiling price (call). The put options are purchased from the counterparty by the Company’s payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays the Company an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty by the Company’s receipt of a cash premium. If the market price is greater than the call strike price for a calculation period, then the Company pays the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.

The Company sells natural gas in the normal course of its business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in natural gas sales. The Company enters into derivative instruments such as swap contracts to hedge a portion of its forecasted natural gas sales.

The Company incurred net payments of $98,562 under these collars during the year ended December 31, 2005. The Company received net payments of $537,375 under these collars during the year ended December 31, 2006 and recorded an unrealized gain on hedges of $301,634.

F-163

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

The Company’s open asset/ (liability) hedging positions as of December 31, 2006 consisted of:

Type	Notional Volume (MCF)	Periods	Fixed Price		Put/ Floor Price		Ceiling/ Call Price		Fair Value
Swap Contracts	60,000	1/07–12/07	$	7.54	$	0	$	0	$	33,530
Collars	240,000	1/07–12/07	$	0	$	8.00	$	14.65		367,837
Total Current Portion	300,000									401,367
Collars	240,000	1/08–12/08	$	0	$	7.00	$	9.35		(56,073	)
Collars	240,000	1/09–12/09	$	0	$	7.00	$	9.35		(43,660	)
Total Long-Term Portion	480,000									(99,733	)
Total Financial Instruments	780,000								$	301,634

8. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The Company estimates the carrying value of long-term debts to approximate fair value due to the debt instruments carrying a market rate of interest.

The Company estimated the fair value of the participation liability associated with Norguard Insurance Company’s term loan to be $2,141,109 and $740,000 as of December 31, 2006 and 2005, respectively.

The fair value of the asset associated with the Company’s hedging instruments is $301,634 at December 31, 2006. The fair value is based on valuation methodologies of the Company’s counterparties. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

9. RELATED PARTY TRANSACTION

The Company has a production payable of $58,038 and $413,734, respectively, due to Rex Royalties as of December 31, 2006 and 2005.

There was a related party payable recorded for distributions due to the general partner for $567,269 at December 31, 2005.

The Company has a related party payable to the general partner for $472,429 at December 31, 2006.

The Company pays a monthly management fee to Rex Energy Operating Corp. The management fee expense for each of 2006 and 2005 was $69,600 and $37,000, respectively. Rex Energy Operating Corp. pays certain administrative costs on behalf of the Company. The payable to Rex Energy Operating Corp. was $0 and $985 at December 31, 2006 and 2005, respectively.

F-164

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

10. MAJOR CUSTOMERS

All of the natural gas extracted from the Company’s wells is sold to Dominion Exploration and Production, Inc. or Dominion Peoples, Inc.

11. COSTS INCURRED IN NATURAL GAS ACQUISITION AND DEVELOPMENT ACTIVITIES

Costs incurred by the Company in natural gas property acquisitions and developments are presented below:

	2006		2005
Natural Gas Property Acquisition Costs	$	3,903	$	6,505
Development Costs		1,482,743		628,572
Total	$	1,486,646	$	635,077

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas.

12. NATURAL GAS CAPITALIZED COSTS

Aggregate capitalized costs for the Company related to natural gas production activities with applicable accumulated depreciation, depletion and amortization is presented below:

	2006			2005
Proved Developed Natural Gas Properties	$	5,796,901		$	4,430,617
Pipelines and Support Equipment		273,574			153,211
Undeveloped Properties		0			0
Total		6,070,475			4,583,828
Less accumulated depreciation, depletion, and amortization		(1,024,040	)		(453,807	)
Total	$	5,046,435		$	4,130,021

F-165

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

13. RESULTS OF NATURAL GAS PRODUCING ACTIVITIES

The results of operations for natural gas producing activities (excluding overhead and interest costs) are presented below:

	2006		2005			2004
Revenue
Natural Gas Sales	$	2,715,674	$	2,818,821		$	932,482
Realized Gains (Losses) on Hedges		537,375		(98,562	)		(32,074	)
Unrealized Gains (Losses) on Hedges		301,634		0			0
Net Sales		3,554,683		2,720,259			900,408
Expenses
Production Expenses		336,939		327,833			169,606
Gas Contract Purchases		428,379		402,317			177,515
Accretion Expense on Asset Retirement Obligation		12,044		6,990			12,881
Depreciation, Depletion, and Amortization		570,499		350,000			103,807
Total Expenses		1,347,861		1,087,140			463,809
Results of Operations for Natural Gas Producing Activities	$	2,206,822	$	1,633,119		$	436,599

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, and other production taxes. In addition, production costs include administrative expenses applicable to support equipment associated with these activities.

Depreciation, depletion, and amortization expense includes those costs associated with capitalization acquisitions and development costs, but does not include the depreciation applicable to support equipment.

There is no provision for income taxes because the Company is a nontaxable entity.

14. NATURAL GAS RESERVE QUANTITIES (UNAUDITED)

The Company’s independent engineers, Netherland, Sewell, and Associates, Inc., have evaluated the Company’s proved reserves associated with the natural gas wells located in Westmoreland County, Pennsylvania.

The Company emphasizes that reserve estimates are inherently imprecise. The natural gas reserve estimates of wells located in Westmorland County, Pennsylvania were generally based upon extrapolation of historical production trends, analogy to similar properties, and volumetric calculations. Accordingly, these estimates are expected to change. These changes could be material and occur in the near term as information becomes available.

Proved natural gas reserves represent the estimated quantities of natural gas which geological and engineering data demonstrate with reasonable accuracy will recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved”

F-166

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed natural gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional gas expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

Presented below is a summary of changes in estimated proved reserves of the natural gas wells located in Westmoreland County, Pennsylvania at December 31, 2006.

	Natural Gas (mcf)
Proved Reserves—Beginning of Period	5,332,378
Extensions, Discoveries, and Other Additions	1,116,991
Revisions of Previous Estimates	(403,205	)
Production	(278,490	)
Proved Reserves—End of Period	5,767,674
Proved Developed Reserves
December 31, 2005	2,885,668
December 31, 2006	2,912,794

15. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS QUANTITIES (UNAUDITED)

Statement of Financial Accounting Standard No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proven reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0 percent annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth the Company’s future net cash flows relating to proved natural gas reserves based on the standardized measure prescribed by SFAS 69 at December 31, 2006:

Future Cash Inflows	(a) $	35,269,327
Future Production Costs		(9,483,600	)
Future Abandonment Costs		(433,443	)
Future Development Costs		(6,328,000	)
Net Future Cash Inflows		19,024,284
Less: Effect of a 10.0% Discount Factor		(10,865,469	)
Standardized Measure of Discounted Future Net Cash Flows	$	8,158,815

(a) Calculated using weighted average prices of $6.12 per mcf of natural gas.

F-167

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

Standardized Measure - Beginning of Period	$	17,420,400
Sales of Natural Gas Produced—Net of Production Costs		(1,859,100	)
Development Costs Incurred		1,366,284
Changes in Future Development Costs		(226,816	)
Changes in Prices and Production Costs		(8,901,540	)
Extensions and Discoveries		507,164
Revisions of Previous Quantity Estimates		(776,835	)
Changes in Timing and Other		(975,277	)
Future Abandonment Costs		(132,485	)
Accretion of Discount		1,737,020
Standardized Measure—End of Period	$	8,158,815

16. LITIGATION

On April 17, 2004, Standard filed a Complaint in the United States District Court for the Western District of Pennsylvania against Buckeye Energy, Inc. (“Buckeye”) seeking a declaratory judgment declaring the respective rights of Standard and Buckeye relating to three agreements regarding the sale of natural gas from wells of Buckeye which had been entered into in the early 1980s. The three contracts provide for a fixed price to be paid by Standard to Buckeye for natural gas produced from the subject wells. From inception of the contracts and continuing for over 20 years, Standard paid Buckeye (or Buckeye’s predecessors to the contracts) a fixed price for gas which did not vary up or down with the market. In 2001, Buckeye and Standard had entered into amendments to the subject agreement, which added a fixed surcharge to the fixed price paid. In 2003, Buckeye contended for the first time that the price owed by Standard under the agreements varied with the market price for natural gas. Because the market price for natural gas had risen above the fixed price, Buckeye demanded over $300,000 for gas purchased since 2002 and stated it intended to charge a market price for the future. Standard asked the court to declare that only a fixed price was due for the gas. Buckeye amended its Amended Counterclaim to claim over $500,000 for gas sold since 2002 and seeking a declaratory judgment as to future prices. Buckeye also moved for the joinder of the Company to the action because Standard had conveyed its rights to the gas contracts to the Company in March 2004 (See Note 2). Standard did not object to the joinder motion and the Company was added as a plaintiff in the action. On January 17, 2005, the parties met in mediation and reached a settlement on the material terms of the dispute. The parties agreed (i) that Standard would pay Buckeye $100,000, (ii) that the price the Company would pay Buckeye for natural gas from the wells at issue in the future would be 50.0 percent of market price received by the Company when it resold the gas (iii) that a $.10 per Mcf surcharge would be payable by the Company, (iv) that the Company would take and pay for up to 100,000 Mcf annually from one of the wells, and (v) that the gas that Buckeye would supply to the Company would be of a merchantable quantity. The agreement reached at the settlement was not reduced to writing. On January 20, 2005, counsel for the plaintiffs, with the full authorization of Buckeye’s counsel, informed the court that the parties had settled. On January 21, 2005, the court entered an order stating that the case had been settled and that the case would be administratively closed pending the filing of a notice of dismissal. On February 4, 2005, new counsel to Buckeye informed the plaintiff’s counsel that a settlement did not exist and that Buckeye intended to proceed with the litigation. On February 11, 2005, Buckeye filed a motion to reopen the case. On February 25, 2005, the Company and Standard filed a motion to enforce the oral settlement agreement entered into on January 17, 2005.

F-168

DOUGLAS WESTMORELAND LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

On February 25, 2005, Buckeye filed a motion in opposition of enforcement of the settlement contending that it had not entered into a definitive oral settlement agreement at the mediation on January 17, 2005, and in the alternative, in the event the court determined that it had done so, any such agreement was required to be in writing. On July 27, 2005, the court held an evidentiary hearing on the motions. On September 29, 2005, the court issued an order finding that the parties entered into an oral settlement on January 17, 2005. On October 27, 2005, Buckeye appealed the order to the United States Court of Appeals for the Third Circuit. On December 16, 2005, the parties entered into a written settlement agreement that amended the oral settlement agreement to, among other things, provide that Douglas would pay Buckeye 55.0 percent of the gross price paid to the Company when it resells the gas. On January 11, 2006, the Court of Appeals for the Third Circuit dismissed Buckeye’s appeal, thus resolving the matter. There is no recorded liability related to this matter.

On November 23, 2004, Dale Campbell (“Campbell”) filed an Amended Complaint in the Court of Common Pleas of Westmoreland County, Pennsylvania against the Company and Douglas Oil & Gas Limited Partnership (“Douglas O&G”), and Standard, seeking a declaratory judgment that the Company and Douglas O&G are required to pay him for natural gas produced at various wells at rates allegedly agreed to under a written agreement and oral agreement between the parties, and account for monies paid to Campbell during the duration of their contractual relationship. The well contracts, which are the subject of this lawsuit, were purchased by the Company in the transaction with Standard (See Note 4). The Company and Douglas O&G filed an Answer and New Matter on March 4, 2005, denying the material allegations of the Amended Compliant and asserting that Campbell’s claims are barred or otherwise fail because, among other reasons, the claims are untimely and because Campbell has already been paid in full. As of December 31, 2006, Campbell had not taken any further action to prosecute the claims asserted in the lawsuit. The Company believes Campbell had postponed any further action in the lawsuit pending resolution of the litigation with Buckeye described above. In the event Campbell takes any action in this lawsuit, the Company intends to vigorously defend the claims that have been asserted it in this action and to seek a dismissal of the action for failure to prosecute. The Company believes that the likelihood of an unfavorable outcome of this matter is remote.

17. SUBSEQUENT EVENTS

As of December 31, 2006, the Company and Douglas Oil & Gas Limited Partnership, as co-borrowers, were not in compliance with the Tangible Net Worth covenant in the term loan agreement requiring that 85.0 percent of December 31, 2005 Tangible Net Worth, as defined in the term loan agreement, increase by $500,000. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarter of 2007.

F-169

Midland Exploration Limited Partnership

F-170

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Midland Exploration Limited Partnership

State College, Pennsylvania

We have audited the accompanying balance sheets of Midland Exploration Limited Partnership as of December 31, 2006 and 2005 and the related statements of operations, changes in partners’ equity and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Midland Exploration Limited Partnership as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

Pittsburgh, Pennsylvania

March 15, 2007

F-171

MIDLAND EXPLORATION LIMITED PARTNERSHIP

BALANCE SHEETS

	December 31,
	2006			2005
ASSETS
CURRENT ASSETS
Cash	$	64,245		$	18,778
Production Receivable		80,231			73,434
Related Party Receivables		0			69,374
Prepaid Expenses		2,088			7,651
Advances for Future Projects		0			1,785
TOTAL CURRENT ASSETS		146,564			171,022
OIL AND GAS PROPERTIES
Proved Developed Oil and Gas Properties		692,637			659,170
Less: Accumulated Depletion and Depreciation		(372,565	)		(210,684	)
NET BOOK VALUE OF OIL AND GAS PROPERTIES		320,072			448,486
TOTAL ASSETS	$	466,636		$	619,508
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES
Related Party Payable	$	20,688		$	0
Accrued Distributions—Related Party		23,139			28,900
Accrued Distributions		102,465			127,979
Accrued Expenses		2,535			0
Accounts Payable		104,193			7,829
TOTAL CURRENT LIABILITIES		253,020			164,708
ASSET RETIREMENT OBLIGATION		8,375			7,613
TOTAL LIABILITIES		261,395			172,321
COMMITMENTS AND CONTINGENCIES (Note 6)
PARTNERS’ EQUITY		205,241			447,187
TOTAL LIABILITIES AND PARTNERS’ EQUITY	$	466,636		$	619,508

SEE ACCOMPANYING NOTES.

F-172

MIDLAND EXPLORATION LIMITED PARTNERSHIP

STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2006		2005		2004
OPERATING REVENUE
Oil and Natural Gas Sales	$	401,754	$	472,697	$	219,248
TOTAL OPERATING REVENUE		401,754		472,697		219,248
OPERATING EXPENSES
Operating Expenses		86,914		22,674		57,308
Production Taxes		40,527		35,906		0
General and Administrative		60,305		34,234		30,088
Depletion and Depreciation		161,881		115,000		26,949
Impairment Charge on Oil and Gas Properties		0		107,119		0
Accretion Expense		762		1,321		0
TOTAL OPERATING EXPENSES		350,389		316,254		114,345
GAIN ON SALE OF OIL AND GAS PROPERTIES		0		0		41,667
NET INCOME	$	51,365	$	156,443	$	146,570

SEE ACCOMPANYING NOTES.

F-173

MIDLAND EXPLORATION LIMITED PARTNERSHIP

STATEMENTS OF CHANGES IN PARTNERS’ EQUITY

YEARS ENDED DECEMBER 31, 2006, 2005, AND 2004

	PARTNERS’ EQUITY
BEGINNING BALANCE—December 31, 2003	$	0
CAPITAL CONTRIBUTIONS		654,946
PARTNER DISTRIBUTIONS		(142,096	)
NET INCOME		146,570
ENDING BALANCE—December 31, 2004	$	659,420
PARTNER DISTRIBUTIONS		(368,676	)
NET INCOME		156,443
ENDING BALANCE—December 31, 2005	$	447,187
PARTNER DISTRIBUTIONS		(293,311	)
NET INCOME		51,365
ENDING BALANCE—December 31, 2006	$	205,241

SEE ACCOMPANYING NOTES.

F-174

MIDLAND EXPLORATION LIMITED PARTNERSHIP

STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	51,365		$	156,443		$	146,570
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depletion and Depreciation		161,881			115,000			26,949
Accretion Expense		762			1,321			0
Gain on Sale of Oil and Gas Properties		0			0			(41,667	)
Impairment of Oil and Gas Properties		0			107,119			0
(Increase) Decrease in
Production Receivable		(6,797	)		(44,600	)		(28,834	)
Prepaid Expenses		5,563			(4,930	)		(2,721	)
Related Party Receivables		69,374			(69,374	)		0
Increase (Decrease) in
Related Party Payable		20,688			(18,359	)		18,359
Accrued Expenses		2,535			0			0
Accounts Payable		96,364			(38,457	)		46,286
NET CASH PROVIDED BY OPERATING ACTIVITIES		401,735			204,163			164,942
CASH FLOWS FROM INVESTING ACTIVITIES
Development of Oil and Gas Properties and Related Equipment		(31,682	)		(156,702	)		(204,892	)
Proceeds from Sale of Prospects		0			0			366,945
Advances for Future Projects		0			(1,785	)		0
NET CASH PROVIDED (USED) BY INVESTING ACTIVITIES		(31,682	)		(158,487	)		162,053
CASH FLOWS FROM FINANCING ACTIVITIES
(Repayment) Advances—Related Party		0			182,923			(182,923	)
Cash Distributions to Partners		(324,586	)		(211,797	)		(142,096	)
NET CASH USED BY FINANCING ACTIVITIES		(324,586	)		(28,874	)		(325,019	)
NET INCREASE IN CASH		45,467			16,802			1,976
CASH—BEGINNING	$	18,778			1,976			0
CASH—ENDING	$	64,245		$	18,778		$	1,976
SUPPLEMENTAL DISCLOSURES
Non-Cash Activity
Distributions to Partners—Accrued	$	125,604		$	156,879		$	0
Contributions of Capital Assets at Formation	$	0		$	0		$	654,946

SEE ACCOMPANYING NOTES.

F-175

MIDLAND EXPLORATION LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Business

Midland Exploration Limited Partnership, a Delaware limited partnership (“Midland” or “Company”) was formed on January 1, 2004. The business of Midland is to evaluate, generate and or acquire oil and natural gas prospects or producing properties in various locations throughout the Permian Basin in the states of Texas and New Mexico. The Company owns interests in approximately 32 wells. Douglas Oil & Gas Limited Partnership, a Delaware limited partnership, owns an 18.42 percent interest in Midland and serves as its general partner. The remaining 81.58 percent is owned by four limited partners. The Company was formed by virtue of the contribution of certain oil and gas properties located in the Permian Basin from Douglas Oil & Gas Limited Partnership and other members of the Company. The capital represents the net book value of the properties contributed from Douglas Oil & Gas Limited Partnership and the other members of the Company.

Basis of Presentation

These financial statements present the financial position, results of operations, and changes in equity and cash flows for Midland only. Midland financial statements are required to be included with the consolidated financial statements of their general partner, Douglas Oil & Gas Limited Partnership, under the guidance of EITF 04-5 – Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights. The Consolidated Financial Statements of Douglas Oil & Gas Limited Partnership are issued separately from these financial statements.

Revenue Recognition

Natural gas and oil revenue is recognized when the oil and natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. In each case it is the measurement of the purchaser that determines the amount of oil or gas purchased (although there are provisions for challenging these measurements if we believe the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil and natural gas production is at our applicable field gathering system; therefore, we do not incur transportation costs related to our sales of oil and natural gas production. The Company does not currently participate in any gas-balancing arrangements. Midland uses the allowance method to account for uncollectible accounts receivable. At December 31, 2006 and 2005, management determined there was no allowance for doubtful accounts.

Income Taxes

The Company is treated as a partnership for federal and state income tax purposes. Accordingly, income taxes are not reflected in the financial statements because the resulting profit or loss is included in the income tax returns of the individual partners.

F-176

MIDLAND EXPLORATION LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

Accounting Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Accordingly, actual results could differ from those estimates. Among the more sensitive of the estimates involves determining the proved reserves from which depletion expense is calculated and determining the future net cash flows from which asset impairment, if any, is ascertained.

Oil and Natural Gas Properties

The Company accounts for its proved oil and natural gas exploration and production activities under the successful efforts method of accounting.

Oil and natural gas property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and natural gas properties. Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of oil and natural gas, are capitalized.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

The Company accounts for impairment under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field to the unamortized capitalized

F-177

MIDLAND EXPLORATION LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

cost of the asset. If the future undiscounted cash flows, based on its estimate of future oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Management determined that properties in 2005 were impaired and recorded expense of $107,119 relating to the impairment. Management determined that there were no impaired properties for the year ended December 31, 2006.

Upon the sale or retirement of proved oil and natural gas property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

Natural Gas and Oil Reserve Quantities

The Company’s estimate of proved reserves is based on the quantities of natural gas and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell, and Associates, Inc. prepare a reserve and economic evaluation of all the Company’s properties on a lease-by-lease basis.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The Company’s independent engineering firm adheres to the same guidelines when preparing their reserve reports. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas, natural gas liquids, and oil eventually recovered.

New Accounting Pronouncements

On March 30, 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for the Company beginning January 1, 2005, and was applied in estimating the asset retirement obligation at December 31, 2005.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas

F-178

MIDLAND EXPLORATION LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Producing Companies” and provides guidance about exploratory well costs to companies that use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling, and (3) an aging of exploratory well costs suspended for greater than one year with the number of wells it is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Application of this pronouncement did not have a significant impact on the Company’s financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,”, a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years.

F-179

MIDLAND EXPLORATION LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. The Company does not expect that adoption of this FASB Staff Position will have a material impact on its results of operations or financial position.

Reclassification

The prior year financial statements have been reclassified to conform to the current year presentation.

2. ASSET RETIREMENT OBLIGATIONS

The Company has adopted SFAS No. 143, “Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS No. 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which the well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of the oil and natural gas properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is reversed. The asset retirement obligation is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0 percent.

A summary of the asset retirement obligation is as follows at December 31:

	2006		2005
Beginning Balance	$	7,613	$	0
Initial Asset Retirement Obligation Capitalized		0		6,292
Asset Retirement Obligation Accretion Expense		762		1,321
Total	$	8,375	$	7,613

3. CONCENTRATION OF CREDIT RISKS

At times during the years ended December 31, 2006 and 2005, the Company’s cash balance may have exceeded the Federal Deposit Insurance Corporation’s insured limit of $100,000. There were no losses incurred due to concentrations.

4. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

F-180

MIDLAND EXPLORATION LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments.

5. RELATED PARTY TRANSACTIONS

During 2005, the Company advanced $40,000 to Rex Energy Limited Partnership and $10,000 to Rex Energy Royalties Limited Partnership, each related parties.

For each of the years ended December 31, 2006 and 2005, the Company paid management fees of approximately $24,000 for overhead, accounting, and professional services to Douglas Oil & Gas Limited Partnership.

The Company had a related party payable recorded for distributions due to the general partner for $23,139 at December 31, 2006. At December 31, 2005 the related party distribution payable was $28,900. There was a related party payable of $20,688 and $0 at December 31, 2006 and 2005 related primarily to management fees. At the end of December 31, 2006 and 2005, there were related party receivables of $0 and $69,374 due from affiliates.

6. COMMITMENTS AND CONTINGENCIES

Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. It has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. It conducts periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort. Management knows of no significant probable or possible environmental contingent liabilities.

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems, conducting third-party environmental reviews, and assessing the potential liability. The Company has not experienced any significant environmental liability and is not aware of any potential environmental issues or claims as of December 31, 2006.

7. PARTNERSHIP AGREEMENT

All profits and losses for the Company are allocated to the partners in accordance with their percentage interests. In accordance with the partnership agreement, all net cash flow is distributed to the partners. At its discretion, the general partner may make additional partnership distributions.

8. COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION AND DEVELOPMENT ACTIVITIES

Costs incurred by the Company in oil and natural gas property acquisitions and developments are presented below:

	2006		2005
Oil and Natural Gas Property Acquisition Costs	$	0	$	6,292
Development Costs		33,467		156,702
Total	$	33,467	$	162,994

F-181

MIDLAND EXPLORATION LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather oil and natural gas.

9. OIL AND NATURAL GAS CAPITALIZED COSTS

Aggregate capitalized costs for the Company related to oil and natural gas production activities with applicable accumulated depreciation and depletion are presented below:

	2006			2005
Proved Oil and Natural Gas Properties	$	692,637		$	659,170
Undeveloped Properties		0			0
Total		692,637			659,170
Less: Accumulated Depreciation and Depletion		(372,565	)		(210,684	)
Total	$	320,072		$	448,486

10. RESULTS OF OIL AND NATURAL GAS PRODUCING ACTIVITIES

The results of operations for oil and natural gas producing activities (excluding overhead and interest costs) are presented below:

	2006		2005		2004
Revenue
Oil and Natural Gas Sales	$	401,754	$	472,697	$	219,248
Expenses
Operating Expenses		86,914		22,674		38,074
Production Taxes		40,527		35,906		19,234
Impairment Charge on Oil and Gas Properties		0		107,119		0
Accretion Expense on Asset Retirement Obligation		762		1,321		0
Depreciation and Depletion		161,881		115,000		26,949
Total Expenses		290,084		282,020		84,257
Results of Operations for Oil and Natural Gas Producing Activities	$	111,670	$	190,677	$	134,991

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, and other production taxes. In addition, production costs include administrative expenses applicable to support equipment associated with these activities.

Depreciation and depletion expense includes those costs associated with capitalization acquisitions and development costs, but does not include the depreciation applicable to support equipment.

There is no provision for income taxes because the Company is a nontaxable entity.

F-182

MIDLAND EXPLORATION LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

11. OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED)

Independent engineers, Netherland, Sewell and Associates, Inc., have evaluated the Company’s interests in proved reserves of the oil and natural gas wells.

The Company emphasizes that reserve estimates are inherently imprecise. The oil and natural gas reserve estimates of wells were generally based upon extrapolation of historical production trends, analogy to similar properties, and volumetric calculations. Accordingly, these estimates are expected to change. These changes could be material and occur in the near term as information becomes available.

Proved oil and natural gas reserves represent the estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil and natural gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

Presented below is a summary of changes in the Company’s interest in the estimated reserves of the oil and natural gas wells. Reserves relate to proved developed properties.

	Oil (bls)		Natural Gas (mcf)		Oil Equivalent
December 31, 2006
Proved Reserves—Beginning of Period	1,521		300,460		51,598
Extensions, Discoveries, and Other Additions	0		0		0
Revisions of Previous Estimates	(21	)	168,147		28,004
Production	(156	)	(94,743	)	(15,947	)
Proved Reserves—End of Period	1,344		373,864		63,655
Proved developed reserves
December 31, 2005	1,521		300,460		51,598
December 31, 2006	1,344		373,864		63,655

F-183

MIDLAND EXPLORATION LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

12. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

Statement of Financial Accounting Standard No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proven reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0 percent annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by SFAS 69 for the year ended December 31, 2006:

Future Cash Inflows	(a) $	1,534,000
Future Production Costs		(451,700	)
Future Abandonment Costs		(86,857	)
Future Development Costs		0
Net Future Cash Inflows		995,443
Less: Effect of a 10.0 Percent Discount Factor		(201,018	)
Standardized Measure of Discounted Future Net Cash Flows	$	794,425

(a) Calculated using weighted average prices of $3.89 per mcf of natural gas and using a weighted average price of $58.50 per bls of oil.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows for the year ended December 31, 2006:

Standardized Measure—Beginning of Period	$	1,688,600
Sales of Natural Gas Produced—Net of Production Costs		(416,529	)
Net Changes in Prices and Production Costs		(1,040,981	)
Future Abandonment Costs		(8,375	)
Changes in Timing and Other		68,616
Revisions of Previous Quantity Estimates		334,234
Accretion of Discount		168,860
Standardized Measure—End of Period	$	794,425

F-184

New Albany-Indiana, LLC

F-185

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of

New Albany-Indiana, LLC

State College, Pennsylvania

We have audited the accompanying balance sheets of New Albany-Indiana, LLC (a development stage company) as of December 31, 2006 and 2005 and the related statements of operations, members’ development stage equity and cash flows for the year ended December 31, 2006 and for the periods from inception to December 31, 2005 and 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of New Albany-Indiana, LLC (a development stage company) as of December 31, 2006 and 2005, and the results of its operations and its cash flows for the year ended December 31, 2006 and for the periods from inception to December 31, 2005 and 2006 in conformity with accounting principles generally accepted in the United States of America.

Pittsburgh, Pennsylvania

March 15, 2007

F-186

NEW ALBANY-INDIANA, LLC

(A DEVELOPMENT STAGE COMPANY)

BALANCE SHEETS

	December 31,
	2006		2005
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	101,903	$	0
Capital Contribution Receivable—Related Party		94,375		0
TOTAL CURRENT ASSETS		196,278		0
DEPOSIT ON WORKING INTEREST IN LEASEHOLD ACREAGE		0		3,500,000
DEVELOPMENT STAGE PROPERTY AND EQUIPMENT
Unproved Acreage		13,186,186		0
Exploratory Wells Pending Determination		2,538,011		0
Asset Retirement Obligation—Asset		16,877		0
Processing Equipment		578,312		0
TOTAL DEVELOPMENT STAGE PROPERTY AND EQUIPMENT		16,319,386		0
TOTAL ASSETS	$	16,515,664	$	3,500,000
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	15,149	$	0
Related Party Payables		3,683		0
Accrued Expenses		1,031,982		0
TOTAL CURRENT LIABILITIES	$	1,050,814		0
ASSET RETIREMENT OBLIGATION		20,534		0
TOTAL LIABILITIES		1,071,348		0
MEMBERS’ EQUITY, including deficit accumulated during development stage of $175,952		15,444,316		3,500,000
TOTAL LIABILITIES AND MEMBERS’ EQUITY	$	16,515,664	$	3,500,000

SEE ACCOMPANYING NOTES.

F-187

NEW ALBANY-INDIANA, LLC

(A DEVELOPMENT STAGE COMPANY)

STATEMENTS OF OPERATIONS

	December 31, 2006			Period from Inception to December 31, 2005		Period from Inception to December 31, 2006
OPERATING REVENUE	$	0		$	0	$	0
INTEREST INCOME		21,230			0		21,230
TOTAL REVENUES AND INCOME		21,230			0		21,230
OPERATING EXPENSES
General and Administrative Expenses		161,515			0		161,515
Dry Hole Costs		35,667			0		35,667
TOTAL OPERATING EXPENSES		197,182			0		197,182
NET LOSS	$	175,952	)	$	0	$	(175,952	)

SEE ACCOMPANYING NOTES.

F-188

NEW ALBANY-INDIANA, LLC

(A DEVELOPMENT STAGE COMPANY)

STATEMENTS OF CHANGES IN MEMBERS’ EQUITY

	Members’ Equity
BEGINNING BALANCE—at Inception	$	0
CAPITAL CONTRIBUTIONS		3,500,000
ENDING BALANCE—December 31, 2005	$	3,500,000
CAPITAL CONTRIBUTIONS		12,120,268
NET LOSS DURING DEVELOPMENT STAGE		(175,952	)
ENDING BALANCE—December 31, 2006	$	15,444,316

SEE ACCOMPANYING NOTES.

F-189

NEW ALBANY-INDIANA, LLC

(A DEVELOPMENT STAGE COMPANY)

STATEMENTS OF CASH FLOWS

	December 31, 2006			Period from Inception to December 31, 2005			Period from Inception to December 31, 2006
CASH FLOWS FROM DEVELOPMENT STAGE
Net Loss	$	(175,952	)	$	0		$	(175,952	)
Adjustments to Reconcile Net Loss to Net Cash Provided During Development Stage
Increase (Decrease) In
Accounts Payable		15,149			0			15,149
Related Party Payables		3,683			0			3,683
NET CASH FLOWS PROVIDED BY DEVELOPMENT STAGE ACTIVITIES		(157,120	)		0			(157,120	)
CASH FLOWS USED BY INVESTING ACTIVITIES
Deposit on Working Interest in Leasehold Acreage		0			(3,500,000	)		(3,500,000	)
Acquisitions of Unproved Acreage		(9,686,186	)					(9,686,186	)
Exploration Oil and Gas Properties and Related Equipment		(2,080,684	)		0			(2,080,684	)
NET CASH FLOWS USED BY INVESTING ACTIVITIES		(11,766,870	)		(3,500,000	)		(15,266,870	)
CASH FLOWS PROVIDED BY FINANCING ACTIVITIES
Capital Contributions Received		12,025,893			3,500,000			15,525,893
NET INCREASE IN CASH		101,903			0			101,903
CASH—BEGINNING		0			0			0
CASH—ENDING	$	101,903		$	0		$	101,903

SEE ACCOMPANYING NOTES.

F-190

NEW ALBANY-INDIANA, LLC

NOTES TO FINANCIAL STATEMENTS

YEAR ENDED DECEMBER, 31, 2006 AND FOR PERIOD FROM INCEPTION

TO DECEMBER 31, 2005

1. ORGANIZATION OF BUSINESS

New Albany-Indiana, LLC (the “Company”) was organized as a limited liability company in the state of Delaware in November 2005. The purpose of the Company is to acquire working interests in leasehold acreage in the Illinois Basin located in Southern Indiana known to contain New Albany Shale formations. Its original members included Rex Energy Operating Corp. (49.0 percent membership interest), Baseline Oil & Gas Corp., a Nevada corporation (“Baseline”) (50.0 percent membership interest), and Rex Energy Wabash, LLC, a Delaware limited liability company (1.0 percent membership interest), which serves as the managing member. Capital contributions from its members in 2005 were $3,500,000. These funds were used as a deposit required under the terms of a purchase agreement with Aurora Energy, Ltd. (“Aurora”), as described below. The Company had no other activity during the period from inception to December 31, 2005.

On January 30, 2006, Rex Energy Operating Corp. withdrew as a member of the Company and assigned its membership interests to several of its affiliates. As of December 31, 2006, Lance T. Shaner has a 23.03 percent membership interest, Shaner & Hulburt Capital Partners Limited Partnership has a 3.77 percent membership interest, Rex Energy II Limited Partnership has an 11.10 percent membership interest and Douglas Oil & Gas Limited Partnership has an 11.10 percent membership interest.

2. SIGNIFICANT ACCOUNTING POLICIES

Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Accordingly, actual amounts could differ from those estimates.

Income Taxes

The Company is taxed as a partnership for federal and state purposes. As such, no provision is made for income taxes because such tax liability is the liability of the members rather than the Company.

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

Oil and Natural Gas Property, Depreciation and Depletion

The Company accounts for its oil exploration and production activities under the successful efforts method of accounting.

Oil and gas property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and natural gas properties. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial

F-191

NEW ALBANY-INDIANA, LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER, 31, 2006 AND FOR PERIOD FROM INCEPTION

TO DECEMBER 31, 2005

reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of oil and gas are capitalized. Workover costs are expensed as incurred.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

The Company accounts for impairment under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas prices, operating costs, anticipated production from proved reserves, and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Management determined that no adjustments to the unamortized capitalized cost were necessary as of December 31, 2006.

Upon the sale or retirement of proved oil and gas property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

New Accounting Pronouncements

On March 30, 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the

F-192

NEW ALBANY-INDIANA, LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER, 31, 2006 AND FOR PERIOD FROM INCEPTION

TO DECEMBER 31, 2005

timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for the Company beginning January 1, 2005, and was applied in estimating the asset retirement obligation at December 31, 2005.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies that use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling, and (3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The pronouncement was applied by the Company when evaluating the exploratory well costs.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure

F-193

NEW ALBANY-INDIANA, LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER, 31, 2006 AND FOR PERIOD FROM INCEPTION

TO DECEMBER 31, 2005

with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require or permit assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. The Company does not expect that adoption of this FASB Staff Position will have a material impact on the Company’s results of operations or financial position.

3. ACQUISITIONS

On February 1, 2006, the Company completed an acquisition of certain oil and gas leases and other associated rights from Aurora Energy, Ltd. (“Aurora”), a Nevada corporation, pursuant to a Purchase and Sale Agreement with Aurora dated November 15, 2005. Under this purchase agreement, the Company purchased from Aurora an undivided 48.75 percent working interest (40.7 percent net revenue interest) in (i) leases covering approximately 58,200 acres in several counties in Indiana (the “Leases”) and (ii) all of Aurora’s rights under a Farmout and Participation Agreement with a third party. In addition, Aurora granted the Company an option, exercisable by the Company until August 1, 2007, to acquire at a fixed price per acre a fifty percent (50.0 percent) working interest in acreage leased or acquired by Aurora or its affiliates in certain other counties located in Indiana. The total purchase price for the acquisition of the working interests in the Leases and Aurora’s rights under the Farmout Agreement, together with Aurora’s grant of the Option, was $10,500,000.

The Company subsequently acquired, through several transactions, an additional 48.75 percent working interest in 63,648 gross acres as of December 31, 2006 for $1,473,462.

On March 3, 2006 the Company completed an acquisition of certain oil and gas leases and other associated rights from Source Rock Resources, Inc. (“Source Rock”), a Delaware corporation, pursuant to a Purchase and Sale Agreement with Source Rock. Pursuant to this purchase agreement, the Company purchased from Source Rock an undivided 45 percent working interests in leases covering approximately 21,070 gross acres for

F-194

NEW ALBANY-INDIANA, LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER, 31, 2006 AND FOR PERIOD FROM INCEPTION

TO DECEMBER 31, 2005

$736,476. In addition, the Company subsequently acquired through several transactions an additional 45 percent working interest in leases covering approximately 17,646 gross acres for $331,900 as of December 31, 2006.

Effective May 1, 2006, the Company entered into a joint operating agreement (the “JOA”) as non-operating party with El Paso Production Company as the operator. Aurora and Pogo Producing Company were also parties to the JOA as non-operators. The JOA was formed to explore and develop the New Albany Shale formation located in Greene County, Indiana, herein referred to as the “Contract Area”. The Company will bear all costs and receive all oil and gas production revenue based on the 17.06 percent working interest it received under the JOA. The operator began drilling the Bogard 1-10H well in the Contract Area in October 2006 for a total cost to the Company of $139,155.

4. CAPITAL CALLS

Capital contributions from its members in 2005 were $3,500,000. These funds were used as a deposit required under the terms of a purchase agreement with Aurora. In accordance with the formation agreement, the Company can require capital contributions from its members. In February 2006, the Company made a capital call from its members in the amount of $6,978,770 to complete the acquisition described in Note 3, herein referred to as the Aurora capital call. Subsequent to the Aurora capital call, the Company made additional capital calls to its members in the amount of $5,141,500 to fund the development of the Aurora acquisition. As of December 31, 2006, $94,375 of this capital call is due from Rex Energy II Limited Partnership. This amount was paid in January 2007. See also Note 8.

5. EXPLORATORY WELLS AND PROVED RESERVES

Effective January 1, 2006, the Company adopted FASB Staff Position No. FAS 19-1; Accounting for Suspended Well Costs. This FASB Staff Position replaces certain paragraphs of FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies (FASB 19) and provided guidance as to whether there are circumstances that would permit the continued capitalization of exploratory well costs beyond one year, other than when additional exploration wells are necessary to justify major capital expenditures and those wells are under way or firmly planned for the near future.

FASB 19 requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs become part of the enterprise’s wells, equipment, and facilities; if, however, the well has not found proved reserves, the capitalized costs of drilling the well are expensed, net of any salvage value. In certain circumstances, an exploratory well finds reserves but those reserves cannot be classified as proved when drilling is completed. To meet the classification of proved reserves, the geological and engineering data must support with reasonable certainty that the quantities of reserves are recoverable under existing economic and operating conditions (typically, prices and costs at the date that the estimate is made).

FASB 19 requires that the cost be carried as an asset provided that (a) there have been sufficient reserves found to justify completion as a producing well if the required capital expenditure is made, and (b) drilling of the additional exploratory wells is under way or firmly planned for the near future. If either of those two criteria is not met, the enterprise must expense the exploratory well costs. The FASB staff believes that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project.

F-195

NEW ALBANY-INDIANA, LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER, 31, 2006 AND FOR PERIOD FROM INCEPTION

TO DECEMBER 31, 2005

Upon adoption of FASB Staff Position FAS 19-1, the Company evaluated all existing capitalized exploratory well costs under the provisions of the FASB Staff Position 19-1. As a result, the Company determined that $2,538,011 of cost was capitalized and is pending determination. The Company also determined that $35,667 of exploratory costs incurred should be expensed. The following table reflects the net change in capitalized exploratory well costs during 2006:

	2006
Beginning Balance at January 1:	$	0
Capitalized Exploratory Well Costs Charged to Expense Upon Adoption of FAS 19-1		0
Additions of Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves		2,573,678
Reclassification of Wells, Facilities, and Equipment Based on the Determination of Proved Reserves		0
Capitalized Exploratory Well Costs Charged to Expense		(35,667	)
Ending Balance at December 31:	$	2,538,011

The total capitalized exploratory well costs that have been capitalized for a period of one year or less is $2,538,011.

6. ASSET RETIREMENT OBLIGATIONS

Effective January 1, 2006, the Company adopted SFAS No. 143, “Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS No. 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which the oil and natural gas well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of our natural gas properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the oil or natural gas well is sold, at which time the liability is reversed. The asset retirement obligation is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0 percent. The Company has recorded accretion expense in the current year pending proved reserves.

A summary of the asset retirement obligation is as follows at December 31:

	2006
Beginning Balance	$	0
Initial Asset Retirement Obligation Capitalized		16,877
Total Asset Retirement Obligation	$	16,877

7. RELATED PARTY TRANSACTIONS

As of December 31, 2006, $94,375 was due from Rex Energy II Limited Partnership to fund a capital call issued by the Company to its members (see Note 4). At December 31, 2006, there was a related party payable to Rex Energy Operating Corp. for $3,683.

Refer to Note 1 Organization of Business for additional related party information.

F-196

NEW ALBANY-INDIANA, LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER, 31, 2006 AND FOR PERIOD FROM INCEPTION

TO DECEMBER 31, 2005

8. SUBSEQUENT EVENTS

Through February 2007, the Company issued two mandatory capital calls to its members totaling $2,120,073. The Company will use the contributed capital to fund leasehold acquisitions and related development, as well as the drilling of wells and related infrastructure.

On January 26, 2007, the Company acquired a 45.0 percent working interest in 2,171 gross acres located in Knox County, Indiana from Source Rock Resources, Inc. for $44,511.

On March 12, 2007, the Company entered into an Extension Agreement with its 50.0 percent member, Baseline Oil & Gas Corp. (“Baseline”). Under the terms of the Extension Agreement, Baseline was granted a one week extension to March 16, 2006 to pay a mandatory capital call issued by the Company to Baseline in the amount of $492,423.66. In addition, the Extension Agreement provides that in the event Baseline pays the Company an additional $1,729,033.47 in outstanding capital calls by March 16, 2007, the Company would agree to redeem Baseline’s 50.0 percent membership interest in the Company pursuant to the terms of a mutually agreed upon redemption agreement (the “Redemption Agreement”). Under the terms of the Redemption Agreement, the Company would agree that in exchange for the redemption of Baseline’s 50.0 percent membership interest in the Company, the Company would assign 50.0 percent of its assets, including its leasehold mineral interests, to Baseline. The Extension Agreement provides that in the event that Baseline fails to pay all outstanding capital calls by March 16, 2006, the Company, and its non-defaulting members, shall be entitled to exercise the rights set forth in Section 3.3(a) of the Company’s limited liability company agreement dated November 25, 2005. Section 3.3(a) provides that in the event a member fails to pay certain mandatory capital calls issued by the managing member of the Company, the Company may permit other non-defaulting members to contribute the amount owed by the defaulting member as an additional capital contribution to the Company. In such event, the membership interests of all members of the Company will be adjusted pursuant to a formula, the numerator of which is the member’s total capital contributions to the Company, and the denominator of which is the sum of all members’ total capital contributions to the Company. The Extension Agreement provides that in the event that Baseline’s membership interest in the Company is reduced in the manner set forth above due to its failure to pay all of the outstanding capital calls, the Company, under the terms of the Redemption Agreement, must immediately thereafter redeem Baseline’s interest in the Company in exchange for the assignment to Baseline of an interest in all of the Company’s assets equal to Baseline’s then reduced membership interest. In the event that Baseline does not pay the full amount of all capital calls outstanding on or before March 16, 2007, the Company believes that the Company’s member, Rex Energy II Limited Partnership, will contribute to the Company an amount equal to that portion of the capital call not paid by Baseline and its membership interest in the Company will be increased accordingly.

F-197

Rex Energy II Limited Partnership

F-198

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Rex Energy II, LP

State College, Pennsylvania

We have audited the balance sheets of Rex Energy II, LP as of December 31, 2006 and 2005 and the related statements of operations, changes in partners’ equity and of cash flows for the years then ended and for the period from inception to December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rex Energy II, LP as of December 31, 2006 and 2005, and the results of its operations and its cash flows for the years then ended and for the period from inception to December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 17 to the financial statements, the Company restated its previously issued 2005 financial statements to correct the reporting of asset retirement obligations.

Pittsburgh, Pennsylvania

March 15, 2007

F-199

REX ENERGY II LIMITED PARTNERSHIP

BALANCE SHEETS

	December 31,
	2006		2005
			Restated
ASSETS
CURRENT ASSETS
Cash	$	57,164	$	1,630,452
Production Receivable		939,784		626,645
Joint Interest Billing Receivables—Net of ‘06 Allowance of $25,454		141,578		51,488
Capital Contributions Receivable		0		139,500
Related Party Receivable		21,352		241,005
Other Receivables		139,231		8,297
Oil Inventory		40,798		116,483
Prepaid Expenses		69,304		31,306
TOTAL CURRENT ASSETS		1,409,211		2,845,176
OIL AND GAS PROPERTY AND EQUIPMENT
Undeveloped Properties		1,043,036		246,193
Wells In Progress		20,300		208,378
Proved Developed Oil and Natural Gas Properties		28,928,079		14,663,687
Other Property and Equipment		9,256		2,254
Total Property and Equipment		30,000,671		15,120,512
Less: Accumulated Depreciation and Depletion		3,042,174		110,774
NET PROPERTY AND EQUIPMENT		26,958,497		15,009,738
INVESTMENT IN NEW ALBANY-INDIANA, LLC		1,714,297		0
TOTAL ASSETS	$	30,082,005	$	17,854,914
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	757,047	$	1,342,221
Production Payable		208,370		243,622
Accrued Expenses		54,956		79,288
Distributions Payable		0		82,714
Capital Contribution Payable		94,375		0
Related Party Payable		78,871		41,947
Financial Instruments Payable—current		5,397		194,837
TOTAL CURRENT LIABILITIES		1,199,016		1,984,629
OTHER LIABILITIES
Line of Credit Facility		3,550,149		0
Asset Retirement Obligation		762,893		288,206
Financial Instruments Payable—long term		134,168		198,534
TOTAL OTHER LIABILITIES		4,447,210		486,740
TOTAL LIABILITIES		5,646,226		2,471,369
PARTNERS’ EQUITY		24,435,779		15,383,545
TOTAL LIABILITIES AND PARTNERS’ EQUITY	$	30,082,005	$	17,854,914

SEE ACCOMPANYING NOTES.

F-200

REX ENERGY II LIMITED PARTNERSHIP

STATEMENTS OF OPERATIONS

	Year Ended December 31,						Period From Inception to December 31,
	2006			2005			2004
				Restated
OPERATING REVENUE
Oil and Natural Gas Sales	$	8,625,042		$	1,092,337		$	8,559
Other Operating Income		336,061			0			0
Realized Gain (Loss) on Hedges		(60,499	)		2,814			0
Unrealized Gain (Loss) on Hedges		253,806			(393,372	)		0
TOTAL OPERATING REVENUE		9,154,410			701,779			8,559
OPERATING EXPENSES
Operating Expenses		2,082,919			254,320			792
Production Taxes		237,830			47,747			0
General and Administrative Expenses		855,473			220,211			36,463
Accretion Expense		73,371			25,946			970
Depreciation, Depletion and Amortization		2,949,433			110,000			1,285
TOTAL OPERATING EXPENSES		6,199,026			658,224			39,510
INCOME (LOSS) FROM OPERATIONS		2,955,384			43,555			(30,951	)
OTHER INCOME (Expense)
Other Income (Expense)—Net		(135,278	)		0			0
Interest Expense		(274,708	)		0			0
Interest Income		10,151			363,308			12,638
TOTAL OTHER INCOME (EXPENSE)		(399,835	)		363,308			12,638
NET INCOME	$	2,555,549		$	406,863		$	(18,313	)

SEE ACCOMPANYING NOTES.

F-201

REX ENERGY II LIMITED PARTNERSHIP

STATEMENTS OF CHANGES IN PARTNERS’ EQUITY

YEARS ENDED DECEMBER 31, 2006, 2005—RESTATED, AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

	Capital Contributions		Capital Distributions			Accumulated Earnings (Deficit)			Total Partners’ Equity
BEGINNING BALANCE—January 1, 2004	$	0	$	0		$	0		$	0
CAPITAL CONTRIBUTIONS		3,999,500								3,999,500
CAPITAL DISTRIBUTIONS				(89,104	)					(89,104	)
NET INCOME							(18,313	)		(18,313	)
ENDING BALANCE—December 31, 2004	$	3,999,500	$	(89,104	)	$	(18,313	)	$	3,892,083
CAPITAL CONTRIBUTIONS		11,640,000								11,640,000
CAPITAL DISTRIBUTIONS				(555,401	)					(555,401	)
NET INCOME							406,863			406,863
ENDING BALANCE—December 31, 2005	$	15,639,500	$	(644,505	)	$	388,550		$	15,383,545
CAPITAL CONTRIBUTIONS		8,581,500								8,581,500
CAPITAL DISTRIBUTIONS				(2,084,815	)					(2,084,815	)
NET INCOME							2,555,549			2,555,549
ENDING BALANCE—December 31, 2006	$	24,221,000	$	(2,729,320	)	$	2,944,099		$	24,435,779

SEE ACCOMPANYING NOTES.

F-202

REX ENERGY II LIMITED PARTNERSHIP

STATEMENTS OF CASH FLOWS

	Years Ended December 31,						Period From Inception to December 31,
	2006			2005			2004
				Restated
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	2,555,549		$	406,863		$	(18,313	)
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities
Depreciation, Depletion and Amortization		2,949,433			110,000			1,285
Accretion Expense		73,371			25,946			970
Equity (Income) Loss in New Albany, LLC		19,530			0			0
Bad Debt Expense		25,454			0			0
Unrealized (Gain) Loss on Hedges		(253,806	)		393,372			0
(Increase) Decrease in
Notes Receivable—Related Party		0			800,000			(800,000	)
Accounts Receivable		(559,617	)		(682,320	)		(4,110	)
Change in Related Party Receivables and Payables		256,577			(193,743	)		(5,315	)
Oil Inventory		75,685			(116,483	)		0
Other Current Assets		(37,998	)		(30,772	)		(534	)
Increase (Decrease) in
Accounts Payable		(620,426	)		1,570,804			15,039
Accrued Expenses		(24,332	)		75,288			4,000
NET CASH PROVIDED BY OPERATING ACTIVITIES		4,459,420			2,358,955			(806,978	)
CASH FLOWS FROM INVESTING ACTIVITIES
Investment In New Albany, LLC		(1,733,827	)		0			0
Acquisition of Oil and Gas Properties and Related Equipment		(10,950,420	)		(14,203,166	)		(278,873	)
Acquisition of Undeveloped Acreage		(796,845	)		(246,203	)		0
Development of Oil and Gas Properties and Related Equipment		(2,749,611	)		(131,492	)		0
NET CASH USED BY INVESTING ACTIVITIES		(16,230,703	)		(14,580,861	)		(278,873	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Line of Credit		4,336,232			0			0
Repayment of Line of Credit		(786,083	)		0			0
Capital Contribution Payable		94,375			0			0
Capital Contributions Received		8,721,000			13,290,000			2,210,000
Capital Distributions Paid		(2,167,529	)		(520,525	)		(41,266	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		10,197,995			12,769,475			2,168,734
NET INCREASE IN CASH		(1,573,288	)		547,569			1,082,883
CASH—BEGINNING		1,630,452			1,082,883			0
CASH—ENDING	$	57,164		$	1,630,452		$	1,082,883
SUPPLEMENTAL DISCLOSURES
Cash Paid for Interest	$	254,808		$	0		$	0

SEE ACCOMPANYING NOTES.

F-203

REX ENERGY II LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Business

Rex Energy II Limited Partnership (the “Company”) was formed June 9, 2004 pursuant to the Delaware Revised Uniform Limited Partnership Act. The purposes of the Company are to (a) acquire, own, operate, manage, lease, develop, sell or otherwise dispose of interest in oil and gas properties and wells or properties related or used in connection with the foregoing, (b) make loans for the acquisition and development of oil and gas properties and pipelines and (c) engage in any other kind of lawful activity for profit related to the foregoing. The general partner of the Company is Rex Energy II, LLC, a Delaware limited liability company. The general partner owns .01 percent and is responsible for the day-to-day management of the Company.

Through December 31, 2006, the Company acquired interests in approximately 165 wells located in Indiana, Illinois, Texas and New Mexico.

Revenue Recognition

Natural gas and oil revenue is recognized when the oil and natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. In each case it is the measurement of the purchaser that determines the amount of oil or gas purchased (although there are provisions for challenging these measurements if we believe the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil and natural gas production is at our applicable field gathering system; therefore, we do not incur transportation costs related to our sales of oil and natural gas production. The Company does not currently participate in any gas-balancing arrangements. The Company uses the allowance method to account for uncollectible accounts receivable. At December 31, 2006 and 2005, management determined the allowance for uncollectible Joint Interest Billing receivables to be $25,454 and $0, respectively.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, long-term debt, a participation liability associated with a long-term debt, fixed rate swap hedges and commodity collars.

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

Income Taxes

The Company is treated as a partnership for federal and state income tax purposes. Accordingly, income taxes are not reflected in the consolidated financial statements because the resulting profit or loss is included in the income tax returns of the individual partners.

Production Receivable

Production receivables correspond to approximately two months of oil and natural gas revenue extracted and sold to buyers. The production receivable is valued at the invoiced amount and does not bear interest. The Company has assessed the financial strength of its customers and records bad debts as necessary.

Joint Interest Billing Receivable

Joint interest billing receivables represent the Company’s billings to the non-operating interests associated with wells and are based on those owners’ working interests in the wells.

Hedging

The Company uses fixed rate swap contracts and commodity collars to manage price risks in connection with the sale of natural gas. The Company accounts for these contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The results of these hedging activities are reflected in the revenue section of the Statements of Operations.

The Company has established the fair value of all derivative instruments using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. The values the Company reports in its financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

SFAS No. 133 establishes accounting and reporting standards requiring derivative instruments (including certain derivative instruments embedded in other contracts or agreements) to be recorded at fair value and included in the balance sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness as defined by SFAS No. 133, is recognized immediately in earnings.

For derivative instruments designated as fair value hedges (in accordance with SFAS No. 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Hedge effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. However, the Company’s evaluations are not documented, and as a result, the Company is recording changes on the derivative valuations through earnings.

Oil and Natural Gas Property, Depreciation and Depletion

The Company accounts for its oil and natural gas exploration and production activities under the successful efforts method of accounting.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

Proved developed oil and natural gas property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and natural gas properties. Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of oil and natural gas are capitalized.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

The Company accounts for impairment under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Management determined that no properties in 2006 and 2005 were impaired.

Upon the sale or retirement of proved oil or natural gas property or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved oil and gas leasehold interests for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Accordingly, actual

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NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

results could differ from those estimates. Among the more sensitive of the estimates involves determining the proved reserves from which depletion expense is calculated and determining the future net cash flows from which asset impairment, if any, is ascertained.

Reclassification

The prior year financial statements have been reclassified to conform to the current year presentation.

Natural Gas and Oil Reserve Quantities

The Company’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The Company’s independent engineering firm adheres to the same guidelines when preparing its reserve reports. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil or natural gas eventually recovered.

Asset Retirement Obligations

Effective June 9, 2004, the Company adopted SFAS No. 143, “Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS No. 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which the oil and natural gas well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of the Company’s oil and natural gas properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the oil and natural gas well is sold, at which time the liability is reserved. The asset retirement obligation is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0 percent.

	2006		2005
Beginning Balance	$	288,206	$	10,670
Initial Asset Retirement Obligation Capitalized		0		9,700
Asset Retirement Obligation Accretion Expense		73,371		25,946
Net Additional Asset Retirement Obligation for New Wells		401,316		241,890
	$	762,893	$	288,206

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REX ENERGY II LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

A restatement of the 2005 Asset Retirement Obligation was required to be made as a result of the Westar Energy, Inc. and Wadi Petroleum, Inc. acquisitions which occurred in 2006 (see Note 3). The initial recognition of the Asset Retirement Obligation associated with the wells acquired occurred in 2005, but should have been recognized in 2006 as this was the period in which the liability was incurred. The 2005 restatement results in the following adjustments:

Net Additional Asset Retirement Obligation for New Wells was previously stated as $552,713 in 2005 and has been reduced by $310,823 to $241,890. The corresponding asset is included with Proved Developed Oil and Natural Gas Properties as stated on the Balance Sheet. The amount previously stated for this account on the 2005 Balance Sheet of $14,974,510 decreased by $310,823 to $14,663,687.

Asset Retirement Obligation Accretion Expense was previously stated as $57,028 in 2005 and has been reduced by $31,082 to $25,946. This restatement resulted in an increase to Net Income in 2005 by $31,082 to $406,863.

The change in the Net Additional Asset Retirement Obligation coupled with the change in the Asset Retirement Obligation Accretion Expense noted above result in a change to the Asset Retirement Obligation shown under Other Liabilities on the Balance Sheet. The amount previously stated for this account on the 2005 Balance Sheet of $630,111 decreased by $341,905 to $288,206.

The impact of the above restatement was reflected in the 2005 Statement of Changes in Partners’ Equity and 2005 Statement of Cash Flows.

New Accounting Pronouncements

On March 30, 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term “conditional asset retirement obligation,” as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for the Company beginning January 1, 2005, and was applied in estimating the asset retirement obligation at December 31, 2005.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies that use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: (1) net changes from period

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NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling, and (3) an aging of exploratory well costs suspended for greater than one year with the number of wells it is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Application of this pronouncement did not have a significant impact on the Company’s financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require or permit assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the

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REX ENERGY II LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. The Company does not expect that adoption of this FASB Staff Position will have a material impact on its results of operations or financial position.

2. CONCENTRATION OF CREDIT RISKS

At times during the year ended December 31, 2006, the Company’s cash balance may have exceeded the Federal Deposit Insurance Corporation insured limit of $100,000. There were no losses incurred due to concentrations.

3. BUSINESS ACQUISITIONS

On August 31, 2005, the Company acquired a 89.1 percent working interest from National Energy Corporation in 4 oil and gas leases covering properties located in Lawrence County, Illinois, for $1,163,646. The acquisition included interests in 37 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was July 1, 2005.

On September 19, 2005, the Company acquired working interest ranging from 19.0 percent to 64.0 percent from Western Oil Producers, Inc. in several oil and gas leases for properties located in Eddy and Lea Counties, New Mexico, for $1,886,820. The acquisition included interests in 15 producing oil and gas wells and related infrastructure and equipment. The effective date of the acquisition was August 1, 2005.

On September 19, 2005, the Company acquired a 89.1 percent working interest from Brandt B. Powell in 3 oil and gas leases covering properties located in Lawrence County, Illinois, for $669,747. The acquisition included interests in 33 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was September 15, 2005.

On December 6, 2005, the Company acquired a 95.5 percent working interest from Hux Oil Corp. and Pioneer Oil Company, Inc. in several oil and gas leases and units covering properties located in Gallatin County, Illinois and Vigo, Sullivan and Posey Counties, Indiana, for $6,756,255. The acquisition included interests in 88 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was December 1, 2005.

In June 2006, the Company acquired a 29.4 percent working interests from four individuals, which is referred to as the “Scaggs Acquisition” for $1,216,597.

During 2006, the Company purchased additional, non-operating, working interests in the same properties that had been acquired in the Western acquisition noted above as effective August 1, 2005. These interests were purchased from various sellers for approximately $1,000,000.

On January 24, 2006, the Company acquired a 96.5 percent working interest from Westar Energy, Inc. in 12 oil and gas leases covering properties located in Glassrock, Midland, Reagan and Upton Counties, Texas, for $5,015,247. The acquisition included interests in 21 producing oil wells, and related infrastructure and equipment. The effective date of the acquisition was January 1, 2006.

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REX ENERGY II LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

On February 7, 2006, the Company acquired a 48.25 percent working interests from Wadi Petroleum, Inc. in 62 oil and gas leases covering properties located in Terrell County, Texas, for $3,674,653. The acquisition included interests in 15 producing gas wells, and related infrastructure and equipment, including interests in a gas gathering system. The effective date of the acquisition was December 1, 2005.

The Company allocated the purchase price for the Westar Energy, Inc. and Wadi Petroleum, Inc. acquisitions as follows:

	Westar			Wadi
Prepaid Expenses	$	7,518		$	16,014
Oil Inventory		11,566			2,234
Oil and Gas Properties		5,318,875			3,700,154
Receivables and Other		0			25,454
Suspended Payables		(81,092	)		0
Asset Retirement Obligation		(241,620	)		(69,203	)
Total	$	5,015,247		$	3,674,653

4. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value of the Company’s long-term debt approximates the fair value as the debt facility carries a market rate of interest.

The fair value of the liability associated with the Company’s hedging instruments is $139,565 and $393,371 at December 31, 2006 and 2005, respectively. The fair value is based on valuation methodologies of the Company’s counterparties. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

5. COMMITMENTS AND CONTINGENCIES

In accordance with the Partnership Agreement of the Company, on September 1, 2011, a special distribution is required to be made to the partners in an amount equal to their “Capital Return” as of that date. However, such distribution may be postponed until September 1, 2014, if such postponement is approved by the vote or written consent of a majority of the limited partners. The Partnership Agreement of the Company defines “Capital Return” as an amount equal to the excess of (a) the amount of capital contributed to the Company by such partner or the predecessor in interest of such partner over (b) the aggregate amount of all distributions other than priority distributions made to such partner or the predecessor in interest of such partner.

Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. It conducts periodic reviews to identify changes in the environmental

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REX ENERGY II LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort. There were no significant environmental obligations probable or possible as of December 31, 2006.

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company has not experienced any significant environmental liability, and is not aware of any potential environmental issues or claims as of December 31, 2006 and 2005.

6. HEDGING ACTIVITIES

The Company’s results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, the Company enters into oil and natural gas hedges. As of December 31, 2006, the Company’s oil and natural gas derivative instruments consisted of commodity collars (put and call options). These instruments allow the Company to predict with greater certainty the effective price to be received for their hedged oil production.

Collars contain a fixed floor price (put) and ceiling price (call). The put options are purchased from the counterparty by the Company’s payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays the Company an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty by the Company’s receipt of a cash premium. If the market price is greater than the call strike price for a calculation period, then the Company pays the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.

The Company (incurred) and received net payments of ($60,499) and $2,814 under these hedges during the years ended December 31, 2006 and 2005, respectively. Unrealized gains and (losses) associated with these hedges are included in earnings and amounted to $253,806 and ($393,372) for the years ended December 31, 2006 and 2005, respectively.

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REX ENERGY II LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

The following is a summary of the Company’s open asset/ (liability) hedging positions as of December 31, 2006:

Hedge Type	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Fixed Price		Put/Floor Price		Ceiling/Call Price		Fair Market Value
Swap Contracts	0	9,000	1/07–9/07	$	59.75	$	0	$	0	$	(22,078	)
Collars	0	48,000	1/07–12/07	$	0	$	55.00	$	61.25		(249,170	)
Collars	0	24,000	1/07–12/07	$	0	$	70.00	$	82.60		163,903
Collars	120,000	0	1/07–12/07	$	0	$	7.00	$	15.05		101,948
Total Current Portion	120,000	81,000								$	(5,397	)
Collars	0	20,154	1/08–7/08			$	62.00	$	70.00	$	(23,962	)
Collars	0	9,596	8/08–12/08			$	62.00	$	69.10		(15,952	)
Collars	0	48,000	1/08–12/08			$	60.00	$	89.25		123,296
Collars	0	47,023	1/09–7/09			$	62.00	$	67.80		(97,158	)
Collars	0	28,784	8/09–12/09			$	62.00	$	66.10		(72,620	)
Collars	114,960	0	1/08–12/08			$	7.00	$	9.35		(26,859	)
Collars	114,960	0	1/09–12/09			$	7.00	$	9.00		(20,913	)
Total Long Term Portion	229,920	153,556								$	(134,168	)
Total Financial Instruments	349,920	234,556								$	(139,565	)

7. RELATED PARTY TRANSACTIONS

As of December 31, 2005, $139,500 of capital contributions receivable were due from related parties. The outstanding capital contributions were paid during 2006.

The general partner of the Company has retained Rex Energy Operating Corp., a related party, to provide certain management and administration services to the Company, such as legal, tax and human resource services. Expense paid to Rex Energy Operating Corp. for 2006 and 2005 was $470,358 and $146,682, respectively. Rex Energy Operating Corp. pays certain administrative costs on behalf of the Company.

As of December 31, 2006, $94,375 was due to New Albany-Indiana, LLC (“New Albany”) to fund a capital call issued by New Albany to its members. See Note 10.

The Company had related party receivables due from affiliates recorded for $21,352 and $241,005 at December 31, 2006 and December 31, 2005, respectively. The Company had related party payables due to affiliates of $78,871 and $41,947 at December 31, 2006 and December 31, 2005.

8. PARTNERSHIP AGREEMENT

Priority distributions are paid to the partners on an annual basis in an amount equal to twice the U. S. Government Ten-Year Treasury Bond Rate, which is reset annually based on the closing rate on January 1^st of each year. During the year ended December 31, 2005, priority distributions were calculated using a rate of 8.64 percent, and the Company issued $555,401 in priority distributions, of which $82,714 were accrued. During the year ended December 31, 2006, priority distributions were calculated using a rate of 8.74 percent, and the Company issued $2,084,815 in priority distributions. No priority distributions were awarded on partners’ capital

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REX ENERGY II LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

contribution receivable or payable balances. The Company’s partnership agreement provides that additional “net cash flow” (as defined in the partnership agreement) shall be distributed each year to the partners in accordance with their respective percentage interests. No additional net cash flow distributions were paid in 2006 and 2005.

The Partnership Agreement of the Company provides that profits are allocated to partners first, in an amount equal to the priority distributions actually paid during the year, and then, in accordance with their respective percentage interests. Losses are allocated to partners in accordance with their respective percentage interests.

9. LINE OF CREDIT FACILITY

On March 24, 2006, the Company entered into a revolving line of credit for up to $3,700,000 with Sovereign Bank. Interest on the loan accrues and is equal to the rate of interest per annum from time to time established by Sovereign Bank as its prime rate of interest. The loan matures on March 24, 2008. Draws on the line were used to fund acquisitions and development costs associated with the Company’s oil and gas properties. The outstanding balance on the line of credit was $3,550,149 as of December 31, 2006, bearing interest at rate equal to 8.75 percent. On February 13, 2007, all outstanding borrowings under the revolving line of credit were refinanced and became outstanding obligations under the Company’s Amended and Restated Credit Facility with Sovereign Bank. See Note 15.

10. INVESTMENTS

During 2006, the Company acquired an 11.10 percent interest in New Albany-Indiana, LLC (“New Albany”), a Delaware limited liability company. The purpose of New Albany is to acquire working interests in leasehold acreage in the Illinois Basin located in Southern Indiana known to contain New Albany Shale formations. In accordance with the terms of New Albany’s limited liability company agreement, capital calls are required from the members to maintain their ownership percentages. As of December 31, 2006, New Albany issued $1,733,827 of capital calls to the Company, of which $1,639,452 were paid during 2006. The remaining unpaid capital call of $94,375 is presented as accrued capital contributions. The Company accounts for its ownership interest in New Albany under the equity method. For the year ended December 31, 2006, the Company recorded a loss of $19,530, to reflect their share of New Albany’s net loss. See Note 15.

11. COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION AND DEVELOPMENT ACTIVITIES

Costs incurred by the Company in oil and natural gas property acquisitions and developments are presented below:

	2006		2005
Oil and Natural Gas Property Acquisition Costs	$	11,351,736	$	14,454,756
Undeveloped Acreage		796,845		246,203
Development Costs		2,844,480		683,693
Total	$	14,993,061	$	15,384,652

Property acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat and gather oil and natural gas.

F-214

REX ENERGY II LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

12. OIL AND NATURAL GAS CAPITALIZED COSTS

Aggregate capitalized costs for the Company related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization is presented below:

	2006			2005
Proved Oil and Natural Gas Properties	$	28,928,079		$	14,663,687
Wells in Progress		20,300			208,378
Other Equipment		9,256			2,254
Undeveloped Properties		1,043,036			246,193
Total	$	30,000,671		$	15,120,512
Less: Accumulated Depreciation and Depletion		(3,042,174	)		(110,774	)
Total	$	26,958,497		$	15,009,738

13. RESULTS OF OIL AND NATURAL GAS PRODUCING ACTIVITIES

The results of operations for oil and natural gas producing activities (excluding overhead and interest costs) are presented below:

	2006			2005			2004
Revenue
Oil and Natural Gas Sales	$	8,625,042		$	1,092,337		$	8,559
Salt Water Disposal Income		209,706			0			0
Realized Gain (Loss) on Hedges		(60,499	)		2,814			0
Unrealized Gain (Loss) on Hedges		253,806			(393,372	)		0
Net Sales		9,028,055			701,779			8,559
Expenses
Operating Expenses		2,082,919			254,320			792
Production Taxes		237,830			47,747			0
Accretion Expense on Asset Retirement Obligation		73,371			25,946			970
Depreciation and Depletion		2,939,133			110,000			1,285
Total Expenses		5,333,253			438,013			3,047
Results of Operations for Oil and Natural Gas Producing Activities	$	3,694,802		$	263,766		$	5,512

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance and other production taxes. In addition, production costs include administrative expenses applicable to support equipment associated with these activities.

Depreciation, depletion and amortization expense includes those costs associated with capitalization acquisitions and development costs, but does not include the depreciation applicable to support equipment.

There is no provision for income taxes because the Company is a nontaxable entity.

F-215

REX ENERGY II LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

14. OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED)

The Company’s independent engineers, Netherland, Sewell and Associates, Inc., have evaluated the Company’s proved reserves associated with its oil and natural gas interests located in Indiana, Illinois, Texas and New Mexico.

The Company emphasizes that reserve estimates are inherently imprecise. The Company’s oil and natural gas reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

Proved oil and natural gas reserves represent the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by oil and natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil and natural gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional gas expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

Presented below is a summary of changes in estimated reserves of the oil and natural gas wells located in Illinois, Indiana, Texas and New Mexico at December 31, 2006:

	Gas (mcf)		Oil (bls)		Oil Equivalent
Proved Reserves—Beginning of Period	4,778,546		1,475,404		2,271,828
Purchases of Reserves in Place	1,373,956		459,258		688,250
Plus/Minus Revisions of Previous Estimates	(187,216	)	(103,638	)	(134,841	)
Production	(248,607	)	(116,765	)	(158,200	)
Proved Reserves—End of Period	5,716,679		1,812,341		2,667,037
Proved developed reserves
December 31, 2005	2,336,106		1,090,799		1,480,150
December 31, 2006	3,471,218		1,381,581		1,960,117

15. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

Statement of Financial Accounting Standard No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proven reserves. The Company has followed these guidelines, which are briefly discussed below.

F-216

REX ENERGY II LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0 percent annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth the Company’s future net cash flows relating to proved natural gas reserves based on the standardized measure prescribed by SFAS 69 at December 31, 2006:

Future Cash Inflows		$147,521,600	(a)
Future Production Costs		(43,956,900	)
Future Abandonment Costs		(1,142,302	)
Future Development Costs		(7,499,300	)
Net Future Cash Inflows		94,923,098
Less: Effect of a 10.0% Discount Factor		(51,945,673	)
Standardized Measure of Discounted Future Cash Flows	$	42,977,425

(a) Calculated using weighted average prices of $60.13 per barrel of oil and $6.26 for natural gas.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

Standardized Measure—Beginning of Period	$	48,261,700
Sales of Product—Net of Production Costs		(6,388,727	)
Purchases of Reserves in Place		3,225,167
Net Changes in Production Costs and Prices		(6,639,416	)
Changes in Future Development Costs		(242,557	)
Development Costs Incurred		2,752,841
Changes in Timing and Other		(1,340,439	)
Revisions of Previous Quantity Estimates		(683,339	)
Future Abandonment Costs		(793,975	)
Accretion of Discount and Timing of Future Cashflows		4,826,170
Standardized Measure—End of Period	$	42,977,425

16. SUBSEQUENT EVENTS

Through February 2007, New Albany-Indiana, LLC issued two mandatory capital calls to its members totaling $2,120,073. In accordance with the terms of New Albany’s limited liability company agreement, the Company’s share of these capital calls is $235,325. In order to remain a member in New Albany, the Company must fund these capital calls. The Company intends to fund the capital calls.

On February 13, 2007, the Company entered into an Amended and Restated Credit Agreement dated as of February 13, 2007 with Sovereign Bank, as Administrative Agent and Lead Arranger on behalf of signatory

F-217

REX ENERGY II LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

lenders which are parties to the agreement from time to time. At the closing of this loan transaction, the outstanding balance under the Company’s revolving line of credit with Sovereign Bank of $3,592,027 was refinanced and became an outstanding obligation under the new credit facility. The new credit facility provides for loans and letters of credit of up to a maximum of $10,000,000. Under the new credit facility, the Company may borrow funds under an alternative base rate or Eurodollar rate. Under the alternative base rate, the Company may borrow funds at a rate per annum equal to the greater of (i) the prime rate in effect on such day (which is defined as the rate of interest per annum publicly announced from time to time by Sovereign Bank as its prime rate in effect at its principal office) and (ii) the Federal Funds Effective Rate (which is defined as the weighted average of the rates on overnight Federal fund transactions with members of the Federal Reserve System) in effect on such day plus  ¹/2 of 1%. Under the Eurodollar rate, the Company may borrow funds a rate per annum equal to the LIBO rate for such period multiplied by the statutory reserve rate. The statutory reserve rate is calculated as a fraction, the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the applicable maximum reserve percentages expressed as a decimal established by the Federal Reserve Board for eurocurrency funding. Borrowings under the new credit facility mature on March 24, 2008. Provided that certain conditions under the credit agreement are met, the Company may at any time and from time to time repay outstanding borrowings under the new credit facility, in whole or in part, without premium or penalty.

Borrowings under the new credit facility are secured by all of the Company’s oil and gas assets located in the states of Illinois and Indiana. In the event that all outstanding borrowings under the credit facility are not repaid by September 30, 2007 or a borrowing base deficiency under the terms of the credit facility otherwise occurs, the lenders may require the Company to grant additional security interests in other oil and gas properties of the Company. The Amended and Restated Credit Agreement requires the Company to meet certain financial covenants and ratios including minimum current assets to liabilities ratio, minimum debt service coverage ratio and minimum interest coverage ratio. In addition, the Company must meet certain requirements regarding quarterly and annual financial reporting and semi-annual oil and gas reserve reporting. The Amended and Restated Credit Agreement also contains non-financial covenants, which restrict the action of the Company with respect to the incurrence of additional indebtedness, sale of the Company’s assets, the making of investments, transactions with affiliated companies, and the creation of additional liens on the assets of the Company. Subsequent to December 31, 2006, the Company borrowed an additional $3,141,878 under the new credit facility. As of February 28, 2007, outstanding borrowings under the new credit facility were $6,692,027. Borrowings under the new credit facility were used to fund the Company’s acquisition of additional oil and gas properties, development costs associated with the Company’s existing oil and gas properties and for general purposes of the Company.

On February 26, 2007, the Company acquired a 90.0 percent working interest in 6 oil and gas leases covering properties located in Hardin County, Texas for $1,080,000. The acquisition included interests in 3 producing oil wells and related infrastructure and equipment. The interests were purchased from the Creditor’s Trust for Central Utilities Production Corp., a creditor’s trust established in connection with a bankruptcy case styled In re Central Utilities Production Corp., Case No. 03-44067, filed in the United States Bankruptcy Court, Eastern District of Texas, Sherman Division. The effective date of the acquisition was February 1, 2007.

On March 12, 2007, New Albany-Indiana, LLC (“New Albany”) entered into an Extension Agreement with its 50.0 percent member, Baseline Oil & Gas Corp. (“Baseline”). Under the terms of the Extension Agreement, Baseline was granted a one week extension to March 16, 2006 to pay a mandatory capital call issued by New Albany to Baseline in the amount of $492,423.66. In addition, the Extension Agreement provides that in the event Baseline pays New Albany an additional $1,729,033.47 in outstanding capital calls by March 16, 2007,

F-218

REX ENERGY II LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2004

New Albany would agree to redeem Baseline’s 50.0 percent membership interest in New Albany pursuant to the terms of a mutually agreed upon redemption agreement (the “Redemption Agreement”). Under the terms of the Redemption Agreement, New Albany would agree that in exchange for the redemption of Baseline’s 50.0 percent membership interest in the company, New Albany would assign 50.0 percent of its assets, including its leasehold mineral interests, to Baseline. The Extension Agreement provides that in the event that Baseline fails to pay all outstanding capital calls by March 16, 2006, New Albany, and its non-defaulting members, shall be entitled to exercise the rights set forth in Section 3.3(a) of the New Albany’s limited liability company agreement dated November 25, 2005. Section 3.3(a) provides that in the event a member fails to pay certain mandatory capital calls issued by the managing member of New Albany, the company may permit other non-defaulting members to contribute the amount owed by the defaulting member as an additional capital contribution to the company. In such event, the membership interests of all members of New Albany will be adjusted pursuant to a formula, the numerator of which is the member’s total capital contributions to the company, and the denominator of which is the sum of all members’ total capital contributions to the company. The Extension Agreement provides that in the event that Baseline’s membership interest in New Albany is reduced in the manner set forth above due to its failure to pay all of the outstanding capital calls, New Albany, under the terms of the Redemption Agreement, must immediately thereafter redeem Baseline’s interest in the company in exchange for the assignment to Baseline of an interest in all of New Albany’s assets equal to Baseline’s then reduced membership interest. In the event that Baseline does not pay the full amount of all capital calls outstanding on or before March 16, 2007, the Company will contribute to New Albany an amount equal to that portion of the capital call not paid by Baseline and its membership interest in New Albany will be increased accordingly.

17. RESTATEMENT OF PREVIOUSLY ISSUED STATEMENTS DUE TO CORRECTIONS

The Company has restated the previously issued 2005 financial statements for matters related to the following: premature capitalization of asset retirement asset and recognition of asset retirement obligation associated with the Westar Energy, Inc. and Wadi Petroleum, Inc. acquisitions. The accompanying financial statements for 2005 have been restated to reflect the corrections discussed in detail at Note 1: Asset Retirement Obligations.

The effect on the Company’s previously issued 2005 financial statements are summarized as follows:

Balance Sheet as of December 31, 2005

	Previously Reported		Increase (Decrease)			Restated
Total Property and Equipment	$	15,431,335	$	(310,823	)	$	15,120,512
Net Property and Equipment	$	15,320,561	$	(310,823	)	$	15,009,738
Total Assets	$	18,165,737	$	(310,823	)	$	17,854,914
Asset Retirement Obligation	$	630,111	$	(341,905	)	$	288,206
Total Liabilities	$	2,813,274	$	(341,905	)	$	2,471,369
Total Partners’ Equity	$	15,352,463	$	31,082		$	15,383,545
Total Liabilities and Partners’ Equity	$	18,165,737	$	(310,823	)	$	17,854,914

Statement of Operations for the Year Ended December 31, 2005

	Previously Reported		Increase (Decrease)			Restated
Accretion Expense	$	57,028	$	(31,082	)	$	25,946
Net Income	$	375,781	$	31,082		$	406,863

F-219

Oil Property acquired from Hux Oil Corp. and Pioneer Oil Company, Inc.

F-220

INDEPENDENT AUDITORS’ REPORT

To the Partners of

Rex Energy II, Limited Partnership

State College, PA

We have audited the accompanying statements of revenues and direct operating expenses of the oil property acquired from Hux Oil Corp. and Pioneer Oil Company, Inc. for the period January 1, 2005 through November 30, 2005 and the year ended December 31, 2004. These financial statements are the responsibility of Rex Energy II, Limited Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the statements of revenue and direct operating expenses are free of material misstatement. An audit of a statement of revenues and direct operating expenses includes examining, on a test basis, evidence supporting the amounts and disclosures in that financial statement. An audit of a statement of revenues and direct operating expenses also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits of the statements of revenues and direct operating expenses provide a reasonable basis for our opinion.

The accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and exclude material expenses, as described in Note 1 to the financial statements, that would not be comparable to those resulting from the proposed future operations of the oil properties and is not intended to be a complete presentation of revenues and expenses.

In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects the revenues and direct operating expenses of the oil property acquired from Hux Oil Corp. and Pioneer Oil Company, Inc. as described in Note 1 for the periods January 1, 2005 through November 30, 2005 and the year ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

Malin, Bergquist & Company, LLP

Pittsburgh, PA

April 11, 2007

F-221

REX ENERGY II, LIMITED PARTNERSHIP

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES—

OIL PROPERTY ACQUIRED FROM HUX OIL CORP. AND PIONEER OIL COMPANY, INC.

FOR THE PERIOD JANUARY 1, 2005 THROUGH NOVEMBER 30, 2005

AND

FOR THE YEAR ENDED DECEMBER 31, 2004

	2005		2004
Revenues—oil sales	$	3,755,997	$	3,051,932
Direct operating expenses		612,767		706,636
Excess of revenues over direct operating expenses	$	3,143,230	$	2,345,296

SEE ACCOMPANYING NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES.

F-222

REX ENERGY II, LIMITED PARTNERSHIP

(OIL PROPERTY ACQUIRED FROM HUX OIL CORP.

AND PIONEER OIL COMPANY, INC.)

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD JANUARY 1, 2005 THROUGH NOVEMBER 30, 2005

AND FOR THE YEAR ENDED DECEMBER 31, 2004

Note 1. BASIS OF PRESENTATION

The accompanying financial statements present the revenues and direct operating expenses of the oil property (the Property) acquired from Hux Oil Corp. (Hux) and Pioneer Oil Company, Inc. (Pioneer) for the period January 1, 2005 through November 30, 2005 and year ended December 31, 2004. The property was purchased by Rex Energy II, Limited Partnership (the Company) on November 30, 2005 for approximately $6.8 million. The Property consists of working interests.

The accompanying statements of revenues and direct operating expenses of the Property do not include general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes since historical expenses of this nature incurred by Hux and Pioneer are not necessarily indicative of the costs to be incurred by the Company.

Revenues in the accompanying statements of revenues and direct operating expenses are recognized on the entitlement method. Direct operating expenses are recognized on the accrual basis and consist of monthly operator overhead costs and other direct costs of operating the Property which were charged to the joint account of working interest owners by the operator of the wells. Direct operating expenses include all costs associated with production, marketing and distribution, including all selling and direct overhead other than costs of general corporate activities.

Historical financial information reflecting financial position, results of operations, and cash flows of the Property is not presented because the purchase price was assigned to the oil property interests and related equipment acquired. Other assets acquired and liabilities assumed were not material. In addition, the Property was a part of larger enterprises prior to the acquisition by the Company, and representative amounts of general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the Property acquired, nor would such allocated historical costs be relevant to future operations of the Property. Development and exploration expenditures related to the Property were insignificant in the relevant periods. Accordingly, the historical statements of revenues and direct operating expenses of Hux’s and Pioneer’s interest in the Property are presented in lieu of the financial statements required under Item 3-05 of Securities and Exchange Commission Regulation S-X.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Note 2. SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL PRODUCING ACTIVITIES (UNAUDITED)

The following reserve estimates present the Company’s estimate of the proven oil reserves and net cash flow of the Property which is a United States property.

The Company emphasizes that reserve estimates are inherently imprecise. Our oil reserve estimates of wells located in Indiana and Illinois were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

F-223

REX ENERGY II, LIMITED PARTNERSHIP

(OIL PROPERTY ACQUIRED FROM HUX OIL CORP.

AND PIONEER OIL COMPANY, INC.)

NOTES TO FINANCIAL STATEMENTS —(Continued)

FOR THE PERIOD JANUARY 1, 2005 THROUGH NOVEMBER 30, 2005

AND FOR THE YEAR ENDED DECEMBER 31, 2004

Proved oil reserves represent the estimated quantities of oil which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by oil and natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

(a) Reserve Quantity Information

Presented below is a summary of changes in estimated reserves of the oil wells at November 30, 2005 and December 31, 2004. The reserves are proved.

	November 30 2005		December 31 2004
	Oil(bls)
Proved Reserves—Beginning of Period	750,608		828,825
Plus/(Minus) Revisions of Previous Estimates	184,651		5,650
Production	(81,193	)	(83,867	)
Proved Reserves—End of Period	854,066		750,608

(b) Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves

The standardized measure of discounted future net cash flows relating to proved oil reserves (Standardized Measure) is a disclosure requirement under Statement of Financial Accounting Standard No. 69.

The Standardized Measure does not purport to be, nor should it be interpreted to present, the fair value of the oil reserves of the Property. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs are based on period-end sales prices for oil, estimated future production of proved reserves and estimated future production and development costs of proved reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

F-224

REX ENERGY II, LIMITED PARTNERSHIP

(OIL PROPERTY ACQUIRED FROM HUX OIL CORP.

AND PIONEER OIL COMPANY, INC.)

NOTES TO FINANCIAL STATEMENTS —(Continued)

FOR THE PERIOD JANUARY 1, 2005 THROUGH NOVEMBER 30, 2005

AND FOR THE YEAR ENDED DECEMBER 31, 2004

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The standardized measure of discounted future net cash flows relating to proved oil reserves is as follows at November 30, 2005 and December 31, 2004:

	2005		2004
Future Cash Inflows	(a) $	45,154,461	(b) $	21,392,320
Future Production Costs		(14,237,536)		(8,647,238)
Future Development Costs		(630,300)		(630,300)
Net Future Cash Inflows		30,286,625		12,114,782
Less: Effect of 10% Discount Factor		(15,023,475)		(5,465,700)
Standardized Measure of Discounted Future Net Cash Flow	$	15,263,150	$	6,649,082

(a) Calculated using weighted average prices of $52.87 per barrel of oil.

(b) Calculated using weighted average prices of $28.50 per barrel of oil.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

	2005			2004
Standardized Measure—Beginning of Period	$	6,649,082		$	7,648,673
Sales of Oil Produced—net of production costs		(3,143,230	)		(2,345,296	)
Net Changes in Prices and Production costs		7,061,468			(384,641	)
Revisions in previous quantity estimate		3,368,603			52,653
Accretion of Discount		664,908			764,867
Changes in timing and other		662,319			912,825
Standardized Measure—End of Period	$	15,263,150		$	6,649,082

Estimates of economically recoverable oil reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geological formations and other matters. Actual quantities of oil may differ materially from the amounts estimated.

F-225

Oil Property acquired from National Energy Corporation

F-226

INDEPENDENT AUDITORS’ REPORT

To the Partners of

Rex Energy II, Limited Partnership

State College, PA

We have audited the accompanying statements of revenues and direct operating expenses of the oil property acquired from National Energy Corporation for the period January 1, 2005 through June 30, 2005 and the year ended December 31, 2004. These financial statements are the responsibility of Rex Energy II, Limited Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the statements of revenue and direct operating expenses are free of material misstatement. An audit of a statement of revenues and direct operating expenses includes examining, on a test basis, evidence supporting the amounts and disclosures in that financial statement. An audit of a statement of revenues and direct operating expenses also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits of the statements of revenues and direct operating expenses provide a reasonable basis for our opinion.

The accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and exclude material expenses, as described in Note 1 to the financial statements, that would not be comparable to those resulting from the proposed future operations of the oil properties and is not intended to be a complete presentation of revenues and expenses.

In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects the revenues and direct operating expenses of the oil property acquired from National Energy Corporation as described in Note 1 for the periods January 1, 2005 through June 30, 2005 and the year ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

Malin, Bergquist & Company, LLP

Pittsburgh, PA

April 11, 2007

F-227

REX ENERGY II, LIMITED PARTNERSHIP

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES—

OIL PROPERTY ACQUIRED FROM NATIONAL ENERGY CORPORATION

FOR THE PERIOD JANUARY 1, 2005 THROUGH JUNE 30, 2005

AND

FOR THE YEAR ENDED DECEMBER 31, 2004

	2005		2004
Revenues—oil sales	$	433,941	$	428,567
Direct operating expenses		184,608		285,414
Excess of revenues over direct operating expenses	$	249,333	$	143,153

SEE ACCOMPANYING NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES.

F-228

REX ENERGY II, LIMITED PARTNERSHIP

(OIL PROPERTY ACQUIRED FROM

NATIONAL ENERGY CORPORATION)

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD JANUARY 1, 2005 THROUGH JUNE 30, 2005

AND FOR THE YEAR ENDED DECEMBER 31, 2004

Note 1. BASIS OF PRESENTATION

The accompanying financial statements present the revenues and direct operating expenses of the oil property (the Property) acquired from National Energy Corporation (National) for the period January 1, 2005 through June 30, 2005 and year ended December 31, 2004. The property was purchased by Rex Energy II, Limited Partnership (the Company) on June 30, 2005 for approximately $1.3 million. The Property consists of working and royalty interests.

The accompanying statements of revenues and direct operating expenses of the Property do not include general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes since historical expenses of this nature incurred by National are not necessarily indicative of the costs to be incurred by the Company.

Revenues in the accompanying statements of revenues and direct operating expenses are recognized on the entitlement method. Direct operating expenses are recognized on the accrual basis and consist of monthly operator overhead costs and other direct costs of operating the Property which were charged to the joint account of working interest owners by the operator of the wells. Direct operating expenses include all costs associated with production, marketing and distribution, including all selling and direct overhead other than costs of general corporate activities.

Historical financial information reflecting financial position, results of operations, and cash flows of the Property is not presented because the purchase price was assigned to the oil property interests and related equipment acquired. Other assets acquired and liabilities assumed were not material. In addition, the Property was a part of a larger enterprise prior to the acquisition by the Company, and representative amounts of general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the Property acquired, nor would such allocated historical costs be relevant to future operations of the Property. Development and exploration expenditures related to the Property were insignificant in the relevant periods. Accordingly, the historical statements of revenues and direct operating expenses of National’s interest in the Property are presented in lieu of the financial statements required under Item 3-05 of Securities and Exchange Commission Regulation S-X.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Note 2. SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL PRODUCING ACTIVITIES (UNAUDITED)

The following reserve estimates present the Company’s estimate of the proven oil reserves and net cash flow of the Property which is a United States property.

The Company emphasizes that reserve estimates are inherently imprecise. Our oil reserve estimates of wells located in Indiana and Illinois were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

F-229

REX ENERGY II, LIMITED PARTNERSHIP

(OIL PROPERTY ACQUIRED FROM

NATIONAL ENERGY CORPORATION)

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD JANUARY 1, 2005 THROUGH JUNE 30, 2005

AND FOR THE YEAR ENDED DECEMBER 31, 2004

Proved oil reserves represent the estimated quantities of oil which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by oil and natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

(a) Reserve Quantity Information

Presented below is a summary of changes in estimated reserves of the oil wells at June 30, 2005 and December 31, 2004. The reserves are proved.

	June 30 2005		December 31 2004
	Oil(bls)
Proved Reserves—Beginning of Period	156,862		162,483
Plus/(Minus) Revisions of Previous Estimates	38,230		6,156
Production	(9,370	)	(11,777	)
Proved Reserves—End of Period	185,722		156,862

(b) Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves

The standardized measure of discounted future net cash flows relating to proved oil reserves (Standardized Measure) is a disclosure requirement under Statement of Financial Accounting Standard No. 69.

The Standardized Measure does not purport to be, nor should it be interpreted to present, the fair value of the oil reserves of the Property. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs are based on period-end sales prices for oil, estimated future production of proved reserves and estimated future production and development costs of proved reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

F-230

REX ENERGY II, LIMITED PARTNERSHIP

(OIL PROPERTY ACQUIRED FROM

NATIONAL ENERGY CORPORATION)

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD JANUARY 1, 2005 THROUGH JUNE 30, 2005

AND FOR THE YEAR ENDED DECEMBER 31, 2004

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The standardized measure of discounted future net cash flows relating to proved oil reserves is as follows at June 30, 2005 and December 31, 2004:

	2005			2004
Future Cash Inflows	(a) $	9,666,837		(b) $	4,470,566
Future Production Costs		(3,917,829	)		(2,326,692	)
Future Development Costs		(632,610	)		(632,610	)
Net Future Cash Inflows		5,116,398			1,511,264
Less: Effect of 10% Discount Factor		(2,017,490	)		(627,722	)
Standardized Measure of Discounted Future Net Cash Flow	$	3,098,908		$	883,542

(a) Calculated using weighted average prices of $52.05 per barrel of oil.

(b) Calculated using weighted average prices of $28.50 per barrel of oil.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

	2005			2004
Standardized Measure—Beginning of Period	$	883,542		$	925,230
Sales of Oil Produced—net of production costs		(249,333	)		(143,153	)
Net Changes in Prices and Production costs		1,490,700			(38,275	)
Revisions in previous quantity estimate		716,767			49,189
Accretion of Discount		88,354			92,523
Changes in timing and other		168,878			(1,972	)
Standardized Measure—End of Period	$	3,098,908		$	883,542

Estimates of economically recoverable oil reserves are of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geological formations and other matters. Actual quantities of oil may differ materially from the amounts estimated.

F-231

Team Energy, LLC Non-Operated Oil Property acquired

F-232

INDEPENDENT AUDITORS’ REPORT

To the Partners of

Rex Energy II, Limited Partnership

State College, PA

We have audited the accompanying statements of revenues and direct operating expenses of the Team Energy Non-operated oil property acquired for the period January 1, 2006 through May 31, 2006 and the years ended December 31, 2005 and 2004. These financial statements are the responsibility of Rex Energy II, Limited Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the statements of revenue and direct operating expenses are free of material misstatement. An audit of a statement of revenues and direct operating expenses includes examining, on a test basis, evidence supporting the amounts and disclosures in that financial statement. An audit of a statement of revenues and direct operating expenses also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits of the statements of revenues and direct operating expenses provide a reasonable basis for our opinion.

The accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and exclude material expenses, as described in Note 1 to the financial statements, that would not be comparable to those resulting from the proposed future operations of the oil properties and is not intended to be a complete presentation of revenues and expenses.

In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects the revenues and direct operating expenses of the Team Energy Non-operated oil property acquired as described in Note 1 for the periods January 1, 2006 through May 31, 2006 and the years ended December 31, 2005 and 2004, in conformity with accounting principles generally accepted in the United States of America.

Malin, Bergquist & Company, LLP

Pittsburgh, PA

April 11, 2007

F-233

REX ENERGY II, LIMITED PARTNERSHIP

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES—

TEAM ENERGY, LLC NON-OPERATED OIL PROPERTY ACQUIRED

FOR THE PERIOD JANUARY 1, 2006 THROUGH MAY 31, 2006

AND

FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004

	2006		2005		2004
Revenues—oil sales	$	205,259	$	316,420	$	284,000
Direct operating expenses		66,460		145,784		147,433
Excess of revenues over direct operating expenses	$	138,799	$	170,636	$	136,567

SEE ACCOMPANYING NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES.

F-234

REX ENERGY II, LIMITED PARTNERSHIP

(TEAM ENERGY NON-OPERATED

OIL PROPERTY ACQUIRED)

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD JANUARY 1, 2006 THROUGH MAY 31, 2006

AND FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004

Note 1. BASIS OF PRESENTATION

The accompanying financial statements present the revenues and direct operating expenses of the Team Energy Non-operated oil property (the Property) acquired from Mssrs. Scaggs, Swager, Phillips, and Legg for the period January 1, 2006 through May 31, 2006 and the years ended December 31, 2005 and 2004. The property was purchased by Rex Energy II, Limited Partnership (the Company) on June 1, 2006 for approximately $1.2 million. The Property consists of working and royalty interests.

The accompanying statements of revenues and direct operating expenses of the Property do not include general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes since historical expenses of this nature incurred by the previous owners are not necessarily indicative of the costs to be incurred by the Company.

Revenues in the accompanying statements of revenues and direct operating expenses are recognized on the entitlement method. Direct operating expenses are recognized on the accrual basis and consist of monthly operator overhead costs and other direct costs of operating the Property which were charged to the joint account of working interest owners by the operator of the wells. Direct operating expenses include all costs associated with production, marketing and distribution, including all selling and direct overhead other than costs of general corporate activities.

Historical financial information reflecting financial position, results of operations, and cash flows of the Property is not presented because the purchase price was assigned to the oil property interests and related equipment acquired. Other assets acquired and liabilities assumed were not material. In addition, the Property was a part of a larger enterprise prior to the acquisition by the Company, and representative amounts of general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the Property acquired, nor would such allocated historical costs be relevant to future operations of the Property. Development and exploration expenditures related to the Property were insignificant in the relevant periods. Accordingly, the historical statements of revenues and direct operating expenses of the former owners’ interest in the Property are presented in lieu of the financial statements required under Item 3-05 of Securities and Exchange Commission Regulation S-X.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Note 2. SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL PRODUCING ACTIVITIES (UNAUDITED)

The following reserve estimates present the Company’s estimate of the proven oil reserves and net cash flow of the Property which is a United States property.

The Company emphasizes that reserve estimates are inherently imprecise. Our oil reserve estimates of wells located in Indiana and Illinois were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

F-235

REX ENERGY II, LIMITED PARTNERSHIP

(TEAM ENERGY NON-OPERATED

OIL PROPERTY ACQUIRED)

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD JANUARY 1, 2006 THROUGH MAY 31, 2006

AND FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004

Proved oil reserves represent the estimated quantities of oil which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by oil and natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

(a) Reserve Quantity Information

Presented below is a summary of changes in estimated reserves of the oil wells at May 31, 2006 and December 31, 2005 and 2004. The reserves are proved.

	May 31 2006		December 31 2005		December 31 2004
	Oil(bls)
Proved Reserves—Beginning of Period	126,460		109,593		123,764
Plus/(Minus) Revisions of Previous Estimates	5,726		22,762		(6,367	)
Production	(3,324	)	(5,895	)	(7,804	)
Proved Reserves—End of Period	128,862		126,460		109,593

(b) Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves

The standardized measure of discounted future net cash flows relating to proved oil reserves (Standardized Measure) is a disclosure requirement under Statement of Financial Accounting Standard No. 69.

The Standardized Measure does not purport to be, nor should it be interpreted to present, the fair value of the oil reserves of the Property. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs are based on period-end sales prices for oil, estimated future production of proved reserves and estimated future production and development costs of proved reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

F-236

REX ENERGY II, LIMITED PARTNERSHIP

(TEAM ENERGY NON-OPERATED

OIL PROPERTY ACQUIRED)

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD JANUARY 1, 2006 THROUGH MAY 31, 2006

AND FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The standardized measure of discounted future net cash flows relating to proved oil reserves is as follows at May 31, 2006 and December 31, 2005 and 2004:

	May 31 2006			December 31 2005			December 31 2004
Future Cash Inflows	(a) $	8,613,112		$	6,740,337		$	3,123,390
Future Production Costs		(2,315,156	)		(1,973,747	)		(1,204,650	)
Future Development Costs		(290,575	)		(290,575	)		(290,575	)
Net Future Cash Inflows		6,007,381			4,476,015			1,628,165
Less: Effect of 10% Discount Factor		(2,250,388	)		(1,672,579	)		(601,000	)
Standardized Measure of Discounted Future Net Cash Flow	$	3,756,993		$	2,803,436		$	1,027,165

(a) Calculated using weighted average prices per barrel of oil of $66.84 at May 31, 2006, $53.30 at December 31, 2005, and $28.50 at December 31, 2004.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

	May 31 2006			December 31 2005			December 31 2004
Standardized Measure—Beginning of Period	$	2,803,436		$	1,027,165		$	1,206,601
Sales of Oil Produced—net of production costs		(138,799	)		(170,636	)		(136,567	)
Net Changes in Prices and Production costs		862,352			1,320,466			(65,118	)
Revisions in previous quantity estimate		175,018			537,356			(70,325	)
Accretion of Discount		280,344			102,717			120,660
Changes in timing and other		(225,358	)		(13,631	)		(28,086	)
Standardized Measure—End of Period	$	3,756,993		$	2,803,436		$	1,027,165

Estimates of economically recoverable oil reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geological formations and other matters. Actual quantities of oil may differ materially from the amounts estimated.

F-237

Rex Energy III LLC

F-238

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of

Rex III, LLC

State College, Pennsylvania

We have audited the balance sheet of Rex III, LLC as of December 31, 2006 and the related statements of operations, changes in members’ equity and cash flows for the period from inception to December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rex III, LLC as of December 31, 2006, and the results of its operations and its cash flows for the period from inception to December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

Pittsburgh, Pennsylvania

March 15, 2007

F-239

REX ENERGY III LLC

BALANCE SHEET

DECEMBER 31, 2006

ASSETS
CURRENT ASSETS
Cash	$	0
Production Receivable		575,234
Joint Interest Billing Receivable		3,549
Related Party Receivable		4,878
Other Receivables		39,230
Financial Instruments—Current Portion		456,498
Oil and Tubing Inventory		378,554
TOTAL CURRENT ASSETS		1,457,943
PROPERTY AND EQUIPMENT
Land		75,000
Building		600,000
Proved Oil Properties		24,166,475
Field Operation Vehicles		488,000
Undeveloped Acreage		197,664
Total Property and Equipment		25,527,139
Less: Accumulated Depreciation and Depletion		(1,933,620	)
NET PROPERTY AND EQUIPMENT		23,593,519
OTHER ASSETS
Financial Instruments—Long Term Portion		120,109
Loan Costs—Net of Accumulated Amortization $86,176		385,746
TOTAL OTHER ASSETS		505,855
TOTAL ASSETS	$	25,557,317
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable		716,200
Accrued Expenses		73,341
Related Party Payable		484,658
Loan Payable—Current Portion		2,475,000
TOTAL CURRENT LIABILITIES		3,749,199
OTHER LIABILITIES
Asset Retirement Obligation		652,331
Loan Payable—Long Term Portion		17,525,000
TOTAL OTHER LIABILITIES		18,177,331
TOTAL LIABILITIES		21,926,530
COMMITMENTS AND CONTINGENCIES (Note 5)
TOTAL MEMBERS’ EQUITY		3,630,787
TOTAL LIABILITIES AND MEMBERS’ EQUITY	$	25,557,317

SEE ACCOMPANYING NOTES.

F-240

REX ENERGY III LLC

STATEMENT OF OPERATIONS

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

OPERATING REVENUE
Oil Sales	$	4,273,371
Realized Gain on Hedges		182,570
Unrealized Gain on Hedges		576,607
TOTAL OPERATING REVENUE		5,032,548
OPERATING EXPENSES
Operating Expenses		1,209,279
Production Taxes		54,581
General and Administrative		148,827
Accretion Expense on Asset Retirement Obligation		59,304
Depreciation, Depletion and Amortization		2,019,796
TOTAL OPERATING EXPENSES		3,491,787
INCOME FROM OPERATIONS		1,540,761
OTHER INCOME (EXPENSE)
Interest Income		1,151
Interest Expense		(926,026	)
Other Income—Net		14,801
TOTAL OTHER EXPENSE		(910,074	)
NET INCOME	$	630,687

SEE ACCOMPANYING NOTES.

F-241

REX ENERGY III LLC

STATEMENT OF CHANGES IN MEMBERS’ EQUITY

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

	Total Members’ Equity
BALANCE—January 1, 2006	$	0
FORMATION CONTRIBUTION		3,000,100
NET INCOME		630,687
BALANCE—December 31, 2006	$	3,630,787

SEE ACCOMPANYING NOTES.

F-242

REX ENERGY III LLC

STATEMENT OF CASH FLOWS

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	630,687
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization		2,019,796
Accretion Expense		59,304
Unrealized Gain on Hedges		(576,607	)
(Increase) Decrease in
Receivables		(575,234	)
Joint Interest Billing Receivable		(3,549	)
Related Party Receivable		(4,878	)
Other Receivables		(39,230	)
Oil and Tubing Inventory		(276,670	)
Increase (Decrease) in
Accounts Payable		692,254
Accrued Expenses		92,800
Related Party Payable		484,658
NET CASH PROVIDED BY OPERATING ACTIVITIES		2,503,331
CASH FLOWS USED BY INVESTING ACTIVITIES
Acquisition of Other Property and Equipment		(1,313,770	)
Acquisition of Oil Properties and Related Equipment		(21,425,589	)
Development of Oil Properties and Related Equipment		(2,292,050	)
NET CASH USED BY INVESTING ACTIVITIES		(25,031,409	)
CASH FLOWS FROM FINANCING ACTIVITIES
Cash Paid for Loan Acquisition Costs		(471,922	)
Proceeds from Long-Term Debt		20,000,000
Proceeds from Formation Contribution		3,000,000
NET CASH USED BY FINANCING ACTIVITIES		22,528,078
NET INCREASE IN CASH		0
CASH—BEGINNING		0
CASH—ENDING	$	0
SUPPLEMENTAL DISCLOSURES
Interest Paid	$	906,734

SEE ACCOMPANYING NOTES.

F-243

REX ENERGY III LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Description of Business

Rex Energy III LLC, which commenced business operations in June 2006, was formed on October 7, 2004 as a Delaware limited liability company pursuant to the Delaware Limited Liability Company Act. Its current members are Shaner Family Partners Limited Partnership, a Pennsylvania limited partnership (41.85 percent economic interest), The Lance T. Shaner Irrevocable Grandchildren’s Trust II (10.0 percent economic interest), Benjamin W. Hulburt (15.0 percent economic interest), Thomas F. Shields (10.0 percent economic interest), Thomas C. Stabley (8.33 percent economic interest), Christopher K. Hulburt (8.33 percent economic interest), Michael S. Carlson (4.17 percent economic interest), Jack Shawver (4.1 percent economic interest) and eight other individuals who in the aggregate own the remaining 3.50 percent economic interest in the Company. On December 14, 2006, Lance T. Shaner transferred his 50.0 economic interest and 50.0 percent voting interest in the Company to Shaner Family Partners Limited Partnership and The Lance T. Shaner Irrevocable Grandchildren’s Trust II, and thereafter withdrew as a member. Shaner Family Partners Limited Partnership, The Lance T. Shaner Irrevocable Grandchildren’s Trust II, Benjamin W. Hulburt and Thomas F. Shields are the voting members of the Company and own a 45.1 percent, 5.1 percent, 24.9 percent and 24.9 percent voting interest in the Company, respectively. The remaining members own non-voting membership interests in the Company. The Company is managed by the voting members. In matters before the Company, the voting members vote in accordance with their respective voting interests in the Company. The vote or written consent of a majority of the outstanding voting interests of the Company is required before action may be taken on behalf of the Company. The purpose of the Company is to acquire, own, operate, manage, lease, develop and sell or otherwise dispose of, interest in oil and gas properties and wells.

On June 28, 2006, the Company acquired average working interests of 72.0 percent in approximately 220 producing oil wells and related infrastructure and equipment located in Posey and Gibson Counties, Indiana, and Lawrence County, Illinois from Team Energy, L.L.C., an Illinois limited liability company (“Team Energy”) and certain other companies affiliated with Team Energy. The effective date of the acquisition was June 1, 2006. The total acquisition price was $22,701,639.

The Company allocated the purchase price as follows:

Producing Oil and Gas Properties	$	21,874,426
Building and Real Estate		825,770
Oil Inventory		101,884
Vehicles and Equipment		488,000
Asset Retirement Obligation		(593,027	)
Prepaid/Accrued Expenses		4,586
Total	$	22,701,639

Income Taxes

The Company is treated as a partnership for federal and state tax purposes. Accordingly, income taxes are not reflected in the financial statements because the resulting profit and loss is included in the income tax returns of the individual members.

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

Production Receivable

Production receivables correspond to approximately one month of oil revenue extracted and sold to buyers. The production receivable is valued at the invoiced amount and does not bear interest. The Company has assessed the financial strength of its customers and has recorded bad debt as necessary.

Joint Interest Receivables

Joint interest receivables represent the Company’s billings to joint working interest owners in wells for which the Company serves as operator and are based on those owners’ working interests in the wells.

Inventory

Inventory consists of well tubing inventory and the Company’s ownership interests in oil held in terminal tanks located in the field. The tubing and oil inventory is valued at cost.

Financial Instruments

The Company’s financial instruments consist of cash, commodity collars, swap contracts, production receivables, accounts payable, and a line of credit facility.

Revenue Recognition

Oil revenue is recognized when the oil is delivered to or collected by the purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves our stock tanks and enters the purchaser’s trucks. It is the measurement of the purchaser that determines the amount of oil purchased (although there are provisions for challenging these measurements if we believe the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil purchases within 30 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil production is at our applicable field gathering system; therefore, we do not incur transportation costs related to our sales of oil production.

Hedging Activities

The Company mainly uses commodity collars and fixed price swaps to manage price risk in connection with the sale of oil and accounts for those contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The results of the Company’s oil hedging activities are reflected in the revenue section of the Statement of Operations.

The Company has established the fair value of all hedging instruments using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. Values the Company reports in its financial statements change as the estimates are revised to reflect actual results, changes in market conditions, or other factors.

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REX ENERGY III LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

SFAS No. 133 establishes accounting and reporting standards requiring hedging activities be recorded at fair value and included in the Balance Sheet as assets or liabilities. The accounting for changes in fair value of a hedging instrument depends on the intended purpose of the hedge and the resulting designation, which is established at the inception of a hedge. For hedging instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in earnings. For hedging instruments designated as fair value hedges (in accordance with SFAS No. 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Hedge effectiveness is measured annually based on the relative changes in fair value between the hedging contract and the hedged item over time. However, the Company’s evaluations are not documented, and as a result, it is recording changes on the derivative valuations through earnings.

Oil Properties and Depreciation and Depletion

The Company accounts for its oil exploration and production activities under the successful efforts method of accounting.

Oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil properties. Oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of oil are capitalized. Workover costs are expensed as incurred.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

Vehicles used in field operations are depreciated over a period of seven years.

The Company accounts for impairment under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field to the unamortized capitalized

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REX ENERGY III LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future oil prices, operating costs, anticipated production from proved reserves, and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Management determined that no adjustments to the unamortized capitalized cost were necessary as of December 31, 2006.

Upon the sale or retirement of proved oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

Accounting Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Accordingly, actual results could differ from those estimates. Among the more sensitive of the estimates involves determining the proved reserves, costs to plug a well, and salvage values of equipment, from which the asset retirement obligation and depletion expense is calculated. Estimates are utilized to determine the fair market value of the Company’s hedges. Also, management’s estimates and assumptions to determine future net cash flows that ascertain asset impairment, if applicable, are subject to variation from actual results.

Oil Reserve Quantities

The Company’s estimate of proved reserves is based on the quantities of oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell, and Associates, Inc. prepares a reserve and economic evaluation of all the Company’s properties on a lease-by-lease basis.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The Company’s independent engineering firm adheres to the same guidelines when preparing its reserve reports. The accuracy of the Company’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil eventually recovered.

Asset Retirement Obligations

The Company applies SFAS No. 143, “Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS No. 143 requires that the fair value of a liability for a retirement obligation be recognized in the

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REX ENERGY III LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

period in which the liability is incurred. For oil and natural gas properties, this is the period in which the oil and natural gas well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of the Company’s oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the oil or natural gas well is sold, at which time the liability is reversed. The asset retirement obligation is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0 percent.

A summary of the asset retirement obligation at December 31, 2006 is as follows:

	2006
Beginning Balance—Asset Retirement Obligation	$	0
Initial Asset Retirment Obligation Incurred		593,027
Current Year Accretion Expense		59,304
Total Asset Retirement Obligation	$	652,331

New Accounting Pronouncements

On March 30, 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for the Company beginning January 1, 2005, and was applied in estimating the asset retirement obligation at December 31, 2005.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies that use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling, and (3) an aging of exploratory well costs suspended for greater than one year with the number of wells it is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Application of this pronouncement did not have a significant impact on the Company’s financial statements.

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REX ENERGY III LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require or permit assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. The Company does not expect that adoption of this FASB Staff Position will have a material impact on its results of operations or financial position.

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REX ENERGY III LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

2. CONCENTRATIONS OF CREDIT RISK

At times during the year ended December 31, 2006, the Company’s cash balance may have exceeded the Federal Deposit Insurance Corporation’s insured limit of $100,000. There were no losses incurred due to concentrations.

By using derivative instruments to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative is positive, the counterparty owes the Company, which creates repayment risk. The Company minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.

3. HEDGING ACTIVITIES

The Company’s results of operations and operating cash flows are impacted by changes in market prices for oil. To mitigate a portion of the exposure to adverse market changes, it entered into oil hedges. As of December 31, 2006, the Company’s oil hedging instruments consisted of collars. These instruments allow the Company to predict with greater certainty the effective oil price to be received for its hedged production.

Collars contain a fixed floor price (put) and ceiling price (call). The put options are purchased from the counterparty by the Company’s payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays the Company an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty by the Company’s receipt of a cash premium. If the market price is greater than the call strike price for a calculation period, then the Company pays the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.

The Company received net payments of $182,570 under these hedges during year ended December 31, 2006, which increased operating revenue. Unrealized gains associated with these hedges are included in operating revenue and amounted to $576,607 for the year ended December 31, 2006. Below is a summary of the Company’s open asset/ (liability) hedging positions as of December 31, 2006:

Hedge Type	Notional Volume (Bls)	Period	Put/Floor Price		Call/Ceiling Price		Fair Market Value
Collars	24,000	1/07–12/07	$	70.00	$	83.75	$	165,980
Collars	96,000	1/07–12/07	$	65.00	$	76.00	$	289,518
Total Current Portion	120,000						$	455,498
Collars	56,000	1/08–7/09	$	65.00	$	76.00	$	108,082
Collars	60,000	8/08–12/08	$	65.00	$	76.05		119,792
Collars	10,000	8/08–12/08	$	62.00	$	70.00		(16,623	)
Collars	7,000	1/09–7/09	$	62.00	$	67.80		(14,464	)
Collars	30,002	8/09–12/09	$	62.00	$	66.10		(75,678	)
Total Long Term Portion	163,002						$	121,109
Total Financial Instruments	283,002						$	576,607

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REX ENERGY III LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

4. CREDIT FACILITIES

On June 28, 2006, the Company entered into a Credit Agreement with Manufacturers and Traders Trust Company (“M&T Bank”), as Letter of Credit Issuer, Lead Arranger and Agent on behalf of signatory lenders which are parties to the agreement from time to time. The credit facility established under the Credit Agreement provides for loans and letters of credit of up to a maximum of $20,000,000. The Credit Agreement provides for a revolving credit loan up to a maximum of $15,000,000 and for term loans in the amount of up to $5,000,000. Interest on each advance under the revolving credit loan and the term loans accrues and is payable at a rate per annum selected by the Company at either a LIBOR based rate or the applicable floating rate. Under the LIBOR based rate option, the Company may borrow funds under the revolving credit loan at a rate per annum equal to LIBOR plus 3.0 percent and under the term loans at a rate per annum equal to LIBOR plus 5.50 percent. Under the applicable floating rate option, the Company may borrow funds under the revolving credit loan at a rate per annum equal to the Base Rate from time to time in effect plus 0.75 percent, and under term loans at a rate per annum equal to the Base Rate from time to time in effect plus 3.25 percent. The Base Rate is defined as the rate of interest per annum then most recently established by M&T Bank as its “prime rate” of interest. Until the maturity date, only monthly payments of interest are required regarding borrowings under the revolving credit loan. As of December 31, 2006, the interest rate associated with the revolving credit loan and term loan was 8.32 percent and 10.82 percent, respectively.

The revolving credit loan terminates on June 27, 2009. The aggregate outstanding principal balance of the revolving credit loans, together with all accrued but unpaid interest thereon is due and payable on the termination date. The term loan matures on December 27, 2008. The principal balance of the term loans is payable as follows:

Payment Date	Principal Amount Due
June 27, 2007	$   625,000.00
December 27, 2007	$1,250,000.00
June 27, 2008	$1,250,000.00
December 27, 2008	The lesser of $1,875,000.00 or the then outstanding principal balance of the term loans.

Provided that certain conditions under the credit agreement are met, the Company may at any time and from time to time repay outstanding borrowings under the new credit facility, in whole or in part, without prepayment penalty, provided that such prepayments must be in minimum amounts of $100,000.

Borrowings under the new credit facility are currently secured by all of the Company’s oil and gas properties, including the properties acquired by the Company from Team Energy described in Note 1. The Credit Agreement requires the Company to meet certain quarterly financial covenants and ratios, including current assets to current liabilities, minimum asset coverage ratio of total reserve value to total funded debt, minimum fixed charge coverage ratio and total funded debt to EBITDAX ratios. In addition, the Company must meet certain requirements regarding quarterly and annual financial reporting and semi-annual oil and gas reserve reporting. The Credit Agreement also contains non-financial covenants, which restrict the action of the Company with respect to certain matters, including the incurrence of additional indebtedness, payment of dividends and distributions, sale of the Company’s assets, the making of investments and loans, changes in structure of the Company, transactions with affiliated companies, and the creation of additional liens on the assets of the Company.

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REX ENERGY III LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

On June 28, 2006, the Company borrowed $20,000,000 under the new credit facility to pay the purchase price for the acquisition of oil and gas properties of Team Energy and affiliated companies (See Note 1). Of this amount, $15,000,000 was borrowed under the revolving credit loan and $5,000,000 was borrowed under the term loan portion of the facility. At December 31, 2006, outstanding borrowings under the new credit facility were $20,000,000, of which $15,000,000 was under the revolving credit loan and $5,000,000 was under the term loan.

As of December 31, 2006, the Company was not in compliance with the negative covenant contained in its credit agreement requiring that its ratio of total reserve value to total funded debt, as defined in the credit agreement, be at least 2.5:1. The Company obtained a written waiver from its lenders regarding its non-compliance with this negative covenant for the fourth quarter of 2006 and the first and second quarter of 2007.

The future minimum repayments are as follows:

2007	$	2,475,000
2008		4,325,000
2009		13,200,000
Total	$	20,000,000

5. COMMITMENTS AND CONTINGENCIES

Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. The Company conducts periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort. Management knows of no significant probable or possible environmental contingent liabilities as of December 31, 2006.

6. RELATED PARTY TRANSACTIONS

As of December 31, 2006 the Company, has a related party receivable due in the amount of $4,878.

Members of the Company have retained Rex Energy Operating Corp., a related party, to provide certain management and administrative services to the Company, such as legal, tax and human resources. Expenses paid to Rex Energy Operating Corp. for such services were $156,405 for the period from inception to December 31, 2006. Rex Energy Operating Corp. pays certain administrative costs on behalf of the Company. As of December 31, 2006, the Company has a payable due to Rex Energy Operating Corp. in the amount of $484,658.

See Note 1 Organization and Description of Business for additional related party information.

7. MAJOR CUSTOMER

The Company sold 100.0 percent of its oil production in the Indiana and Illinois fields to Countrymark Cooperative, LLP in 2006.

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REX ENERGY III LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

8. FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments.

The fair value of the assets associated with the Company’s hedging instruments is $576,607 at December 31, 2006. The fair value is based on valuation methodologies of its counterparty. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

9. COSTS INCURRED IN OIL ACQUISITION AND DEVELOPMENT ACTIVITIES

Costs incurred by the Company in oil property acquisitions and developments are presented below and include the acquisition described in Note 1:

	2006
Oil Property Acquisition Costs	$	21,874,428
Undeveloped Acreage		197,664
Development Costs		2,292,050
Total	$	24,364,140

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather oil.

10. OIL PROPERTY CAPITALIZED COSTS

Aggregate capitalized costs for the Company related to oil production activities with applicable accumulated depreciation and depletion are presented below:

	2006
Proved Oil Properties	$	24,166,475
Field Operation Vehicles		488,000
Undeveloped Acreage		197,664
Total		24,852,139
Less: Accumulated Depreciation and Depletion		(1,925,496	)
Total	$	22,926,643

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REX ENERGY III LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

11. RESULTS OF OIL PRODUCING ACTIVITIES

The results of operations for oil producing activities (excluding overhead and interest costs) are presented below:

	2006
Revenue
Oil Sales	$	4,273,371
Realized Gain on Hedges		182,570
Unrealized Gain on Hedges		576,607
Net Oil Sales		5,032,548
Expenses
Operating Expenses		1,209,279
Production Taxes		54,581
Accretion Expense on Asset Retirement Obligation		59,304
Depreciation and Depletion		1,925,496
Total Expenses		3,248,660
Results of Operations for Oil Producing Activities	$	1,783,888

There is no provision for income taxes because the Company is a nontaxable entity.

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, and other production taxes. In addition, production costs include administrative expenses applicable to support equipment associated with these activities.

Depreciation and depletion expense includes those costs associated with capitalization acquisitions and development costs, but does not include the depreciation applicable to support equipment.

12. OIL RESERVE QUANTITIES (UNAUDITED)

The Company’s independent engineers, Netherland, Sewell and Associates, Inc., have evaluated the Company’s proved reserves associated with its oil interests located in Indiana and Illinois.

The Company emphasizes that reserve estimates are inherently imprecise. Its oil reserve estimates of the Company’s interests were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

Proved oil reserves represent the estimated quantities of oil which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by oil and natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved”

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REX ENERGY III LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

Presented below is a summary of changes in estimated reserves associated with the Company’s mineral interests located in Illinois and Indiana at December 31, 2006:

	Oil (bls)
Proved Reserves—Beginning of Period	0
Plus Purchases of Reserves in Place	1,879,552
Production	(69,204	)
Proved Reserves—End of Period	1,810,348
Proved developed reserves
December 31, 2005	—
December 31, 2006	1,407,926

13. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

Statement of Financial Accounting Standard No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proven reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0 percent annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following sets forth the Company’s future net cash flows relating to proved oil reserves based on the standardized measure prescribed by SFAS 69 at December 31, 2006:

Future Cash Inflows		(a)  $  102,765,700
Future Production Costs		(31,392,500	)
Future Abandonment Costs		(1,257,113	)
Future Development Costs		(4,749,800	)
Net Future Cash Inflows		65,366,287
Less: Effect of a 10.0% Discount Factor		(23,362,518	)
Standardized Measure of Discounted Future Cash Flows	$	42,003,769

(a) Calculated using weighted average prices of $56.76 per barrel of oil.

F-255

REX ENERGY III LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 2006

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

Standardized Measure—Beginning of Period	$	0
Purchases of Reserves In Place		42,640,226
Sale of Product—Net of Production Costs		(2,959,146	)
Development Costs Incurred		2,322,689
Standardized Measure—End of Period	$	42,003,769

14. SUBSEQUENT EVENTS

As of December 31, 2006, the Company was not in compliance with the negative covenant contained in its credit agreement requiring that its ratio of total reserve value to total funded debt, as defined in the credit agreement, be at least 2.5:1. The Company obtained a written waiver from its lenders regarding its non-compliance with this negative covenant for the fourth quarter of 2006 and the first and second quarter of 2007.

F-256

Oil Property acquired from Team Energy, LLC

F-257

INDEPENDENT AUDITORS’ REPORT

To the Members of

Rex Energy III LLC

State College, PA

We have audited the accompanying statements of revenues and direct operating expenses of the oil property acquired from Team Energy, LLC for the period January 1, 2006 through May 31, 2006 and the years ended December 31, 2005 and 2004. These financial statements are the responsibility of Rex Energy III LLC’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the statements of revenue and direct operating expenses are free of material misstatement. An audit of a statement of revenues and direct operating expenses includes examining, on a test basis, evidence supporting the amounts and disclosures in that financial statement. An audit of a statement of revenues and direct operating expenses also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits of the statements of revenues and direct operating expenses provide a reasonable basis for our opinion.

The accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and exclude material expenses, as described in Note 1 to the financial statements, that would not be comparable to those resulting from the proposed future operations of the oil properties and is not intended to be a complete presentation of revenues and expenses.

In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects the revenues and direct operating expenses of the oil property acquired from Team Energy, LLC as described in Note 1 for the periods January 1, 2006 through May 31, 2006 and the years ended December 31, 2005 and 2004, in conformity with accounting principles generally accepted in the United States of America.

Malin, Bergquist & Company, LLP

Pittsburgh, PA

April 11, 2007

F-258

REX ENERGY III LLC

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES—

OIL PROPERTY ACQUIRED FROM TEAM ENERGY, LLC

FOR THE PERIOD JANUARY 1, 2006 THROUGH MAY 31, 2006

AND

FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004

	2006		2005		2004
Revenues—oil sales	$	3,095,956	$	6,023,311	$	4,497,985
Direct operating expenses		945,374		1,930,096		1,789,127
Excess of revenues over direct operating expenses	$	2,150,582	$	4,093,215	$	2,708,858

SEE ACCOMPANYING NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES.

F-259

REX ENERGY III LLC

(OIL PROPERTY ACQUIRED FROM

TEAM ENERGY, LLC)

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD JANUARY 1, 2006 THROUGH MAY 31, 2006

AND FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004

Note 1. BASIS OF PRESENTATION

The accompanying financial statements present the revenues and direct operating expenses of the oil property (the Property) acquired from Team Energy, LLC (Team) for the period January 1, 2006 through May 31, 2006 and the years ended December 31, 2005 and 2004. The property was purchased by Rex Energy III LLC (the Company) on June 1, 2006 for approximately $22 million. The Property consists of working and royalty interests.

The accompanying statements of revenues and direct operating expenses of the Property do not include general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes since historical expenses of this nature incurred by Team are not necessarily indicative of the costs to be incurred by the Company.

Revenues in the accompanying statements of revenues and direct operating expenses are recognized on the entitlement method. Direct operating expenses are recognized on the accrual basis and consist of monthly operator overhead costs and other direct costs of operating the Property which were charged to the joint account of working interest owners by the operator of the wells. Direct operating expenses include all costs associated with production, marketing and distribution, including all selling and direct overhead other than costs of general corporate activities.

Historical financial information reflecting financial position, results of operations, and cash flows of the Property is not presented because the purchase price was assigned to the oil property interests and related equipment acquired. Other assets acquired and liabilities assumed were not material. In addition, the Property was a part of a larger enterprise prior to the acquisition by the Company, and representative amounts of general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the Property acquired, nor would such allocated historical costs be relevant to future operations of the Property. Development and exploration expenditures related to the Property were insignificant in the relevant periods. Accordingly, the historical statements of revenues and direct operating expenses of Team’s interest in the Property are presented in lieu of the financial statements required under Item 3-05 of Securities and Exchange Commission Regulation S-X.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Note 2. SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL PRODUCING ACTIVITIES (UNAUDITED)

The following reserve estimates present the Company’s estimate of the proven oil reserves and net cash flow of the Property which is a United States property.

The Company emphasizes that reserve estimates are inherently imprecise. Our oil reserve estimates of wells located in Indiana and Illinois were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

F-260

REX ENERGY III LLC

(OIL PROPERTY ACQUIRED FROM

TEAM ENERGY, LLC)

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD JANUARY 1, 2006 THROUGH MAY 31, 2006

AND FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004

Proved oil reserves represent the estimated quantities of oil which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by oil and natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

(a) Reserve Quantity Information

Presented below is a summary of changes in estimated reserves of the oil wells at May 31, 2006 and December 31, 2005 and 2004. The reserves are proved.

	May 31 2006		December 31 2005		December 31 2004
	Oil(bls)
Proved Reserves—Beginning of Period	1,826,561		1,577,458		1,750,661
Plus/(Minus) Revisions of Previous Estimates	80,245		361,311		(49,598	)
Production	(50,145	)	(112,208	)	(123,605	)
Proved Reserves—End of Period	1,856,661		1,826,561		1,577,458

(b) Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves

The standardized measure of discounted future net cash flows relating to proved oil reserves (Standardized Measure) is a disclosure requirement under Statement of Financial Accounting Standard No. 69.

The Standardized Measure does not purport to be, nor should it be interpreted to present, the fair value of the oil reserves of the Property. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs are based on period-end sales prices for oil, estimated future production of proved reserves and estimated future production and development costs of proved reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

F-261

REX ENERGY III LLC

(OIL PROPERTY ACQUIRED FROM

TEAM ENERGY, LLC)

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD JANUARY 1, 2006 THROUGH MAY 31, 2006

AND FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The standardized measure of discounted future net cash flows relating to proved oil reserves is as follows at May 31, 2006 and December 31, 2005 and 2004:

	May 31 2006			December 31 2005			December 31 2004
Future Cash Inflows	(a) $	124,099,266		$	97,355,711		$	44,957,547
Future Production Costs		(38,477,011	)		(33,104,371	)		(19,880,422	)
Future Development Costs		(5,149,245	)		(5,149,245	)		(5,149,245	)
Net Future Cash Inflows		80,473,010			59,102,095			19,927,880
Less: Effect of 10% Discount Factor		(29,584,893	)		(21,938,302	)		(7,739,481	)
Standardized Measure of Discounted Future Net Cash Flow	$	50,888,117		$	37,163,793		$	12,188,399

(a) Calculated using weighted average prices per barrel of oil of $66.84 at May 31, 2006, $53.50 at December 31, 2005, and $28.50 at December 31, 2004.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

	May 31 2006			December 31 2005			December 31 2004
Standardized Measure—Beginning of Period	$	37,163,794		$	12,188,400		$	13,843,405
Sales of Oil Produced—net of production costs		(2,150,582	)		(4,093,215	)		(2,708,858	)
Net Changes in Prices and Production costs		12,220,347			17,311,579			(597,110	)
Revisions in previous quantity estimate		2,340,119			7,991,830			(481,094	)
Accretion of Discount		3,716,379			1,218,840			1,384,341
Changes in timing and other		(2,401,939	)		2,546,360			747,716
Standardized Measure—End of Period	$	50,888,118		$	37,163,794		$	12,188,400.

Estimates of economically recoverable oil reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geological formations and other matters. Actual quantities of oil may differ materially from the amounts estimated.

F-262

Rex Energy II Alpha Limited Partnership

F-263

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Rex Energy II Alpha, LP

State College, Pennsylvania

We have audited the balance sheets of Rex Energy II Alpha, LP as of December 31, 2006 and 2005 and the related statements of operations, changes in partners’ equity and cash flows for the year ended December 31, 2006 and the period from inception to December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rex Energy II Alpha, LP as of December 31, 2006 and 2005, and the results of its operations and its cash flows for the year ended December 31, 2006 and the period from inception to December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.

Pittsburgh, Pennsylvania

March 15, 2007

F-264

REX ENERGY II ALPHA LIMITED PARTNERSHIP

BALANCE SHEETS

	December 31,
	2006		2005
ASSETS
CURRENT ASSETS
Cash	$	2,606	$	6,005
Production Receivable from Related Party		6,447		8,807
Related Party Receivables		36,804		9,412
Inventory		858		0
Prepaid Expenses		167		494
TOTAL CURRENT ASSETS		46,882		24,718
OIL AND GAS PROPERTY AND EQUIPMENT
Undeveloped Properties		1,952		1,329
Wells In Progress		0		19,859
Proved Developed Oil and Natural Gas Properties		1,207,102		728,122
Total Property and Equipment		1,209,054		749,310
Less: Accumulated Depreciation and Depletion		159,900		5,315
NET PROPERTY AND EQUIPMENT		1,049,154		743,995
TOTAL ASSETS	$	1,096,036	$	768,713
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	0	$	10,000
Related Party Payable		1,944		4,486
Accrued Distributions to Partners		0		11,298
Accrued Expenses		402		13,228
TOTAL CURRENT LIABILITIES		2,346		39,012
OTHER LIABILITIES
Financial Instruments Payable		10,923		0
Asset Retirement Obligation		38,131		31,337
TOTAL OTHER LIABILITIES		49,054		31,337
TOTAL LIABILITIES		51,400		70,349
PARTNERS’ EQUITY		1,044,636		698,364
TOTAL LIABILITIES AND PARTNERS’ EQUITY		$1,096,036		$768,713

SEE ACCOMPANYING NOTES.

F-265

REX ENERGY II ALPHA LIMITED PARTNERSHIP

STATEMENTS OF OPERATIONS

	Year Ended December 31, 2006			Period From Inception to December 31, 2005
OPERATING REVENUE
Oil and Natural Gas Sales	$	424,403		$	96,102
Other Operating Revenue		9,969			0
Unrealized Gain (Loss) on Hedges		(10,923	)		0
TOTAL OPERATING REVENUE		423,449			96,102
OPERATING EXPENSES
Operating Expenses		103,695			27,085
Production Taxes		9,310			3,682
General and Administrative Expenses		31,979			24,109
Accretion Expense		3,605			2,849
Depreciation and Depletion		154,585			5,315
TOTAL OPERATING EXPENSES		303,174			63,040
INCOME FROM OPERATIONS		120,275			33,062
OTHER INCOME
Interest Income		858			6,793
TOTAL OTHER INCOME		858			6,793
NET INCOME	$	121,133		$	39,855

SEE ACCOMPANYING NOTES.

F-266

REX ENERGY II ALPHA LIMITED PARTNERSHIP

STATEMENTS OF CHANGES IN PARTNERS’ EQUITY

YEAR ENDED DECEMBER 31, 2006 AND PERIOD FROM INCEPTION

TO DECEMBER 31, 2005

	Capital Contributions		Capital Distributions			Accumulated Earnings		Total Partners’ Equity
CAPITAL CONTRIBUTIONS	$	690,000	$	0		$	0	$	690,000
CAPITAL DISTRIBUTIONS				(31,491	)				(31,491	)
NET INCOME							39,855		39,855
ENDING BALANCE— December 31, 2005	$	690,000	$	(31,491	)	$	39,855	$	698,364
CAPITAL CONTRIBUTIONS		310,000							310,000
CAPITAL DISTRIBUTIONS				(84,861	)				(84,861	)
NET INCOME							121,133		121,133
ENDING BALANCE— December 31, 2006	$	1,000,000	$	(116,352	)	$	160,988	$	1,044,636

SEE ACCOMPANYING NOTES.

F-267

REX ENERGY II ALPHA LIMITED PARTNERSHIP

STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2006			Period From Inception to December 31, 2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	121,133		$	39,855
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities
Depreciation and Depletion		154,585			5,315
Accretion Expense		3,605			2,849
Unrealized Loss on Hedges		10,923			0
(Increase) Decrease in
Related Party Receivables		(27,392	)		(8,807	)
Production Receivable		2,360			(9,412	)
Inventory		(858	)		0
Prepaid Expenses		327			(494	)
Increase (Decrease) in
Accounts Payable		(10,000	)		10,000
Relate Party Payable		(2,542	)		4,486
Accrued Distributions to Partners		(11,298	)		11,298
Accrued Expenses		(12,826	)		13,228
NET CASH PROVIDED BY OPERATING ACTIVITIES		228,017			68,318
CASH FLOWS USED BY INVESTING ACTIVITIES
Acquisition of Oil and Gas Properties and Related Equipment		(310,000	)		(701,455	)
Development of Oil and Gas Properties and Related Equipment		(146,555	)		(19,367	)
NET CASH USED BY INVESTING ACTIVITIES		(456,555	)		(720,822	)
CASH FLOWS FROM FINANCING ACTIVITIES
Capital Contributions Received		310,000			690,000
Capital Distributions		(84,861	)		(31,491	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		225,139			658,509
NET (DECREASE) INCREASE IN CASH		(3,399	)		6,005
CASH—BEGINNING		6,005			0
CASH—ENDING	$	2,606		$	6,005

SEE ACCOMPANYING NOTES.

F-268

REX ENERGY II ALPHA LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

YEAR ENDED DECEMBER 31, 2006 AND THE PERIOD

FROM INCEPTION TO DECEMBER 31, 2005

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Business

Rex Energy II Alpha Limited Partnership (the “Company”) was formed March 3, 2005 pursuant to the Delaware Revised Uniform Limited Partnership Act. The Company consists of the general partner, Rex Energy II, LLC (2.0 percent) and one limited partner (98.0 percent). The general partner owns a 2.0 percent interest in the Company until such time as the limited partner has received its capital contribution, plus a 15.0 percent compounded annual return on such capital contribution, at which point the general partner’s percentage interest in the Company will increase to 22.0 percent and the limited partner’s percentage interest will decrease by 20.0 percent. When the limited partner has received its capital contributions, plus a 20.0 percent compounded annual return, the general partner’s percentage interest in the Company will increase to 42.0 percent and the limited partner’s percentage interest will decrease by 20.0 percent.

The purposes of the Company are (a) to invest in the activities listed in (b), (c), and (d) of this paragraph on a side-by-side basis with Rex Energy II Limited Partnership in direct proportion to the Capital Accounts of the Company and Rex Energy II Limited Partnership, (b) to acquire, own, operate, manage, lease, develop, sell or otherwise dispose of interests in oil and gas properties and wells or properties related or used in connection with the foregoing, (c) to make loans for the acquisition and development of oil and gas properties and pipelines, and (d) to engage in any other kind of lawful activity for profit related to the foregoing. As of December 31, 2006 the Company has ownership interest in approximately 165 wells. The general partner of the Company is Rex Energy II, LLC, a Delaware limited liability company. The general partner is responsible for the day-to-day management of the Company.

The Company had spent all available capital contributions from its partners with the closing of the February 2006 acquisition from Wadi Petroleum, Inc. (See Note 3). The Company was no longer able to continue investing on a side-by-side basis with Rex Energy II Limited Partnership.

All net cash flow, if any, is required to be distributed with respect to any period in proportion to the percentage interests of the partners for such period. For the period from inception to December 31, 2005, distributions earned were $31,490, of which $20,192 were paid as of December 31, 2005. The Company accrued the remaining $11,298 of distributions, which were paid in 2006. For the year ended December 31, 2006, distribution earned and paid were $84,861.

Revenue Recognition

Natural gas and oil revenue is recognized when the oil and natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. In each case it is the measurement of the purchaser that determines the amount of oil or gas purchased (although there are provisions for challenging these measurements if we believe the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such

F-269

REX ENERGY II ALPHA LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER 31, 2006 AND THE PERIOD

FROM INCEPTION TO DECEMBER 31, 2005

production to ensure that receivables from those purchasers are collectible. The point of sale for our oil and natural gas production is at our applicable field gathering system; therefore, we do not incur transportation costs related to our sales of oil and natural gas production. The Company does not currently participate in any gas-balancing arrangements. The Company uses the allowance method to account for uncollectible accounts receivable. At December 31, 2006 and 2005, management determined the allowance for uncollectible receivables to be $0.

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

Income Taxes

The Company is treated as a partnership for federal and state income tax purposes. Accordingly, income taxes are not reflected in the consolidated financial statements because the resulting profit or loss is included in the income tax returns of the individual partners.

Production Receivable

All of the Company’s production receivable is due from Rex Energy II Limited Partnership, and correspond to approximately one-two months of oil and natural gas revenue extracted and sold to buyers. The production receivable is valued at the invoiced amount and does not bear interest. The Company has assessed the financial strength of its customers and records bad debts as necessary.

Reclassification

The prior year financial statements have been reclassified to conform to the current year presentation.

Oil and Natural Gas Property, Depreciation and Depletion

The Company accounts for its oil and natural gas exploration and production activities under the successful efforts method of accounting.

Proved developed oil and natural gas property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and natural gas properties. Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of oil and natural gas are capitalized.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of- production method, the quantities of recoverable oil and natural gas are established based on estimates made by

F-270

REX ENERGY II ALPHA LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER 31, 2006 AND THE PERIOD

FROM INCEPTION TO DECEMBER 31, 2005

our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

The Company accounts for impairment under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Management determined that no properties in 2006 and 2005 were impaired.

Upon the sale or retirement of proved oil or natural gas property or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Accordingly, actual results could differ from those estimates. Among the more sensitive of the estimates involves determining the proved reserves from which depletion expense is calculated and determining the future net cash flows from which asset impairment, if any, is ascertained.

Natural Gas and Oil Reserve Quantities

The Company’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with

F-271

REX ENERGY II ALPHA LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER 31, 2006 AND THE PERIOD

FROM INCEPTION TO DECEMBER 31, 2005

changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The Company’s independent engineering firm adheres to the same guidelines when preparing its reserve reports. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.

Asset Retirement Obligations

The Company accounts for its asset retirement obligation under the provisions of SFAS No. 143, “Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS No. 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which the oil and natural gas well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of the Company’s oil and natural gas properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the oil and natural gas well is sold, at which time the liability is reserved. The asset retirement obligation is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0 percent.

	2006		2005
Beginning Balance	$	31,337	$	0
Asset Retirement Obligation Accretion Expense		3,605		2,849
Net Additional Asset Retirement Obligation for New Wells		3,189		28,488
	$	38,131	$	31,337

Hedging Activities

The Company may enter into hedging activities. The Company mainly uses collars to manage price risk in connection with the sale of oil and natural gas and accounts for those contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The results of the Company’s oil and natural gas hedging activities are reflected in the revenue section of the Statement of Operations.

The Company has established the fair value of all hedging instruments using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. Values the Company reports in its financial statements change as the estimates are revised to reflect actual results, changes in market conditions, or other factors.

SFAS No. 133 establishes accounting and reporting standards requiring hedging activities to be recorded at fair value and included in the Balance Sheet as assets or liabilities. The accounting for changes in fair value of a hedging instrument depends on the intended purpose of the hedge and the resulting designation, which is established at the inception of a hedge. For hedging instruments designed as cash flow hedges, changes in fair

F-272

REX ENERGY II ALPHA LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER 31, 2006 AND THE PERIOD

FROM INCEPTION TO DECEMBER 31, 2005

value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in earnings. For hedging instruments designated as fair value hedges (in accordance with SFAS No. 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Hedge effectiveness is measured annually based on the relative changes in fair value between the hedging contract and the hedged item over time. However, the Company’s evaluations are not documented, and as a result, it is recording changes on the derivative valuations through earnings.

New Accounting Pronouncements

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies that use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling, and (3) an aging of exploratory well costs suspended for greater than one year with the number of wells it is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Application of this pronouncement did not have a significant impact on the Company’s financial statements.

On March 30, 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for the Company beginning January 1, 2005, and was applied in estimating the asset retirement obligation at December 31, 2005.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

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REX ENERGY II ALPHA LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER 31, 2006 AND THE PERIOD

FROM INCEPTION TO DECEMBER 31, 2005

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require or permit assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. The Company does not expect that adoption of this FASB Staff Position will have a material impact on its results of operations or financial position.

2. CONCENTRATION OF CREDIT RISKS

At times during the period ended December 31, 2006, the Company’s cash balance may have exceeded the Federal Deposit Insurance Corporation insured limit of $100,000. There were no losses incurred due to concentrations.

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REX ENERGY II ALPHA LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER 31, 2006 AND THE PERIOD

FROM INCEPTION TO DECEMBER 31, 2005

3. BUSINESS ACQUISITIONS

On August 31, 2005, the Company acquired a 9.9 percent working interest from National Energy Corporation in 4 oil and gas leases covering properties located in Lawrence County, Illinois, for $129,294. The acquisition included interests in 37 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was July 1, 2005.

On September 19, 2005, the Company acquired an average 1.5 percent working interest from Western Oil Producers, Inc. in several oil and gas leases for properties located in Eddy and Lea Counties, New Mexico, for $189,980. The acquisition included interests in 15 producing oil and gas wells and related infrastructure and equipment. The effective date of the acquisition was August 1, 2005.

On September 19, 2005, the Company acquired a 9.9 percent working interest from Brandt B. Powell in 3 oil and gas leases covering properties located in Lawrence County, Illinois, for $74,416. The acquisition included interests in 33 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was September 15, 2005.

On December 6, 2005, the Company acquired a 3.0 percent working interest from Hux Oil Corp. and Pioneer Oil Company, Inc. in several oil and gas leases and units covering properties located in Gallatin County, Illinois and Vigo, Sullivan and Posey Counties, Indiana, for $210,000. The acquisition included interests in 88 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was December 1, 2005.

On January 24, 2006, the Company acquired an average 3.0 percent working interest from Westar Energy, Inc in 12 oil and gas leases covering properties located in Glassrock, Midland, Reagan and Upton Counties, Texas, for $160,000. The acquisition included interests in 21 producing oil wells, and related infrastructure and equipment. The effective date of the acquisition was January 1, 2006.

On February 7, 2006, the Company acquired an average 1.5 percent working interests from Wadi Petroleum, Inc. in 62 oil and gas leases covering properties located in Terrell County, Texas, for $150,000. The acquisition included interests in 15 producing gas wells, and related infrastructure and equipment, including interests in a gas gathering system. The effective date of the acquisition was December 1, 2005.

4. COMMITMENTS AND CONTINGENCIES

Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. It conducts periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort. There were no significant environmental obligations probable or possible as of December 31, 2006.

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company has not experienced any significant environmental liability, and is not aware of any potential environmental issues or claims as of December 31, 2006.

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REX ENERGY II ALPHA LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER 31, 2006 AND THE PERIOD

FROM INCEPTION TO DECEMBER 31, 2005

5. RELATED PARTY TRANSACTIONS

The general partner of the Company has retained Rex Energy Operating Corp., a related party, to provide certain management and administrative services to the Company, such as legal, tax, and human resource services. The amount paid to Rex Energy Operating Corp. for these services for the year and period from inception to December 31, 2006 and 2005 was $15,000 and $5,528, respectively. Rex Energy Operating Corp. pays certain administrative costs on behalf of the Company.

The Company had related party receivables due from affiliates recorded for $36,804 and $9,412 at December 31, 2006 and December 31, 2005, respectively. The Company had related party payables due to affiliates of $1,944 and $4,486 at December 31, 2006 and December 31, 2005.

Refer to Note 1 under Description of Business for additional related party information.

6. FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying value of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

The fair value of the liability associated with the Company’s hedging instruments is $10,923 at December 31, 2006. The fair market value is based on valuation methodologies of the Company’s counterparty. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value.

7. COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION AND DEVELOPMENT ACTIVITIES

Costs incurred by the Company in oil and natural gas property acquisitions and developments are presented below:

	2006		2005
Oil and Natural Gas Property Acquisition Costs	$	313,189	$	729,943
Development Costs		146,555		26,667
Total	$	459,744	$	756,610

Property acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather oil and natural gas.

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REX ENERGY II ALPHA LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER 31, 2006 AND THE PERIOD

FROM INCEPTION TO DECEMBER 31, 2005

8. OIL AND NATURAL GAS CAPITALIZED COSTS

Aggregate capitalized costs for the Company related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization is presented below:

	2006			2005
Proved Oil and Natural Gas Properties	$	1,207,102		$	728,122
Wells in Progress		0			19,859
Undeveloped Properties		1,952			1,329
Total	$	1,209,054		$	749,310
Less: Accumulated Depreciation and Depletion		(159,900	)		(5,315	)
Total	$	1,049,154		$	743,995

9. RESULTS OF OIL AND NATURAL GAS PRODUCING ACTIVITIES

The results of operations for oil and natural gas producing activities (excluding overhead and interest costs) are presented below:

	2006			2005
Revenue
Oil and Natural Gas Sales	$	424,403		$	96,102
Salt Water Disposal Income		6,023			0
Unrealized Loss on Hedges		(10,923	)		0
Net Sales		419,503			96,102
Expenses
Operating Expenses		103,695			27,085
Production Taxes		9,310			3,682
Accretion Expense on Asset Retirement Obligation		3,605			2,849
Depreciation and Depletion		154,585			5,315
Total Expenses		271,195			38,931
Results of Operations for Oil and Natural Gas Producing Activities	$	148,308		$	57,171

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance and other production taxes. In addition, production costs include administrative expenses applicable to support equipment associated with these activities.

Depreciation, depletion and amortization expense includes those costs associated with capitalization acquisitions and development costs, but does not include the depreciation applicable to support equipment.

There is no provision for income taxes because the Company is a nontaxable entity.

F-277

REX ENERGY II ALPHA LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER 31, 2006 AND THE PERIOD

FROM INCEPTION TO DECEMBER 31, 2005

10. HEDGING ACTIVITIES

The Company’s results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, it entered into oil and natural gas hedges. As of December 31, 2006, the Company’s oil and natural gas hedging instruments consisted of collars. These instruments allow the Company to predict with greater certainty the effective oil and natural gas price to be received for its hedged production.

Collars contain a fixed floor price (put) and ceiling price (call). The put options are purchased from the counterparty by the Company’s payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays the Company an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty by the Company’s receipt of a cash premium. If the market price is greater than the call strike price for a calculation period, then the Company pays the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.

The Company did not incur any net payments under these hedges during the year ended December 31, 2006. Unrealized losses associated with these hedging contracts are included in operating revenue and amounted to $10,923 for the year ended December 31, 2006. Below is a summary of the Company’s open asset/ (liability) hedging positions as of December 31, 2006:

Hedge Type	Notional Volume (Mcf)	Notional Volume (Bls)	Period	Put/Floor Price		Ceiling/Call Price		Fair Market Value
Collars	0	848	1/08–7/08	$	62.00	$	70.00	$	(1,009	)
Collars	0	404	8/08–12/08	$	62.00	$	69.10		(672	)
Collars	0	1,978	1/09–7/09	$	62.00	$	67.80		(4,090	)
Collars	0	1,218	8/09–12/09	$	62.00	$	66.10		(3,057	)
Collars	5,040	0	1/08–12/08	$	7.00	$	9.35		(1,178	)
Collars	5,040	0	1/09–12/09	$	7.00	$	9.00		(917	)
Total Financial Instruments	10,080	4,447						$	(10,923	)

11. OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED)

Independent engineers, Netherland, Sewell and Associates, Inc., have evaluated the Company’s proved reserves of the oil and natural gas wells located in Indiana, Illinois, Texas and New Mexico.

The Company emphasizes that reserve estimates are inherently imprecise. The Company’s oil and natural gas reserve estimates of wells were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

Proved oil and natural gas reserves represent the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by oil and natural gas and (b) the immediately adjoining portions not yet drilled, but which

F-278

REX ENERGY II ALPHA LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER 31, 2006 AND THE PERIOD

FROM INCEPTION TO DECEMBER 31, 2005

can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil and natural gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional gas expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

Presented below is a summary of changes in the Company’s estimated reserves of the oil and natural gas wells located in Illinois, Indiana, Texas, and New Mexico at December 31, 2006:

	Gas (mcf)		Oil (bls)		Oil Equivalent
Proved Reserves—Beginning of Period	246,082		91,640		132,654
Plus/Minus Revisions of Previous Estimates	17,993		(9,409	)	(6,410	)
Production	(60,975	)	(5,859	)	(16,022	)
Proved Reserves—End of Period	203,100		76,372		110,222
Proved developed reserves
December 31, 2005	194,883		64,984		97,465
December 31, 2006	161,611		59,318		86,253

12. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

Statement of Financial Accounting Standard No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proven reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0 percent annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

F-279

REX ENERGY II ALPHA LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEAR ENDED DECEMBER 31, 2006 AND THE PERIOD

FROM INCEPTION TO DECEMBER 31, 2005

The following summary sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by SFAS 69 at December 31, 2006:

Future Cash Inflows	(a) $	5,134,900
Future Production Costs		(1,875,300	)
Future Abandonment Costs		(57,870	)
Future Development Costs		(258,800	)
Net Future Cash Inflows		2,942,930
Less: Effect of a 10.0% Discount Factor		(1,609,561	)
Standardized Measure of Discounted Future Cash Flows	$	1,333,369

(a) Calculated using weighted average prices of $55.94 per barrel of oil and $4.25 for natural gas.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

Standardized Measure—Beginning of Period	$	2,017,700
Sales of Product—Net of Production Costs		(311,235	)
Net Changes in Production Costs and Prices		(488,350	)
Changes in Future Development Costs		(5,830	)
Development Costs Incurred		146,555
Changes in Timing and Other		8,592
Revisions of Previous Quantity Estimates		(197,702	)
Future Abandonment Costs		(38,131	)
Accretion of Discount		201,770
Standardized Measure—End of Period	$	1,333,369

F-280

Rex Energy Royalties Limited Partnership

F-281

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Rex Energy Royalties Limited Partnership

State College, Pennsylvania

We have audited the accompanying balance sheets of Rex Energy Royalties Limited Partnership as of December 31, 2006 and 2005 and the related statements of operations, changes in partners’ equity and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rex Energy Royalties Limited Partnership as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

Pittsburgh, Pennsylvania

March 15, 2007

F-282

REX ENERGY ROYALTIES LIMITED PARTNERSHIP

BALANCE SHEETS

	December 31,
	2006			2005
ASSETS
CURRENT ASSETS
Cash	$	1,482		$	711
Royalty Receivable from Related Party		58,038			413,734
Related Party Receivable		8,277			3,683
TOTAL CURRENT ASSETS		67,797			418,128
COST OF ROYALTY INTERESTS
Royalty Interests in Natural Gas Properties		1,500,000			1,500,000
Less: Accumulated Depletion		(258,162	)		(134,914	)
NET BOOK VALUE OF ROYALTY INTERESTS		1,241,838			1,365,086
TOTAL ASSETS	$	1,309,635		$	1,783,214
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES
Related Party Payable	$	0		$	10,374
Accrued Distributions to Partners		0			300,000
Accrued Expenses		0			8,000
TOTAL CURRENT LIABILITIES		0			318,374
PARTNERS’ EQUITY		1,309,635			1,464,840
TOTAL LIABILITIES AND PARTNERS’ EQUITY		$1,309,635			$1,783,214

SEE ACCOMPANYING NOTES.

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REX ENERGY ROYALTIES LIMITED PARTNERSHIP

STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2006		2005			2004
OPERATING REVENUE
Royalty Revenue	$	686,238	$	790,720		$	404,478
Hedging Settlements		0		(23,195	)		(31,645	)
TOTAL OPERATING REVENUE		686,238		767,525			372,833
OPERATING EXPENSES
Management Fee—Rex Energy Operating Corp.		18,192		28,007			17,933
General and Administrative		64,929		23,107			8,286
Depletion Expense		123,249		80,747			54,166
TOTAL OPERATING EXPENSES		206,370		131,861			80,385
NET INCOME	$	479,868	$	635,664		$	292,448

SEE ACCOMPANYING NOTES.

F-284

REX ENERGY ROYALTIES LIMITED PARTNERSHIP

STATEMENTS OF CHANGES IN PARTNERS’ EQUITY

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

	Partners’ Equity
BEGINNING BALANCE—December 31, 2003	$	438,683
CAPITAL CONTRIBUTIONS		1,040,000
PRIORITY DISTRIBUTIONS		(103,488	)
EXCESS DISTRIBUTIONS		(112,500	)
NET INCOME		292,448
ENDING BALANCE—December 31, 2004	$	1,555,143
CAPITAL CONTRIBUTIONS		0
PRIORITY DISTRIBUTIONS		(103,467	)
EXCESS DISTRIBUTIONS		(622,500	)
NET INCOME		635,664
ENDING BALANCE—December 31, 2005	$	1,464,840
CAPITAL CONTRIBUTIONS		0
PRIORITY DISTRIBUTIONS		(49,073	)
EXCESS DISTRIBUTIONS		(586,000	)
NET INCOME		479,868
ENDING BALANCE—December 31, 2006	$	1,309,635

SEE ACCOMPANYING NOTES.

F-285

REX ENERGY ROYALTIES LIMITED PARTNERSHIP

STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	479,868		$	635,664		$	292,448
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depletion		123,249			80,747			54,166
(Increase) Decrease in
Royalty Receivable		355,697			(350,843	)		(62,890	)
Other Receivable		(4,594	)		(3,683	)		0
Increase (Decrease) in
Related Party Payable		(10,374	)		2,611			7,763
Accrued Expenses		(8,000	)		2,000			6,000
NET CASH PROVIDED BY OPERATING ACTIVITIES		935,846			366,496			297,487
CASH FLOWS USED BY INVESTING ACTIVITIES
Purchases of Natural Gas Royalty Interests		0			0			(1,500,000	)
CASH FLOWS FROM FINANCING ACTIVITIES
Capital Contributions		0			0			1,040,000
Distributions to Partners		(935,075	)		(425,967	)		(215,988	)
NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES		(935,075	)		(425,967	)		824,012
NET INCREASE (DECREASE) IN CASH		771			(59,471	)		(378,501	)
CASH—BEGINNING		711			60,182			438,683
CASH—ENDING	$	1,482		$	711		$	60,182
SUPPLEMENTAL DISCLOSURES
Non-Cash Activity
Distributions to Partners—Accrued	$	0		$	300,000		$	0

SEE ACCOMPANYING NOTES.

F-286

REX ENERGY ROYALTIES LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Business

Rex Energy Royalties Limited Partnership (“Rex Royalties” or the “Company”) was formed pursuant to the Delaware Revised Uniform Limited Partnership Act on September 1, 2002. As of December 31, 2006, Rex Royalties consists of the general partner, Douglas Oil and Gas Limited Partnership (10.0 percent) and fourteen Class A limited partners (90.0 percent). The general partner owns a 10.0 percent interest in Rex Royalties until such point as the Company has returned all invested capital to the limited partners, through excess cash distributions, at which point the general partner will own 50.0 percent of the Company. The Company’s purpose is to acquire, own, or otherwise dispose of royalty interests. Currently the Company has royalty interests in approximately 49 natural gas wells located in Westmorland County, Pennsylvania. The Company does not engage in the acquisition of working interests in oil and gas properties, or engage in the exploration, development, production, or operational activities with respect to any oil and gas property.

Basis of Presentation

These financial statements present the financial position, results of operations, and changes in equity and cash flows for Rex Royalties only. Rex Royalties financial statements are required to be included with the consolidated financial statements of their general partner, Douglas Oil & Gas Limited Partnership, under the guidance of EITF 04-5—Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights. The Consolidated Financial Statements of Douglas Oil & Gas Limited Partnership are issued separately from these financial statements.

Distributions to Class A Limited Partners

Class A limited partners of the Company are entitled to receive priority distributions. Priority distributions are defined as a preferential distribution of net cash flow equal to 8.0 percent per annum of the Class A limited partners’ undistributed capital accounts. Remaining net cash flow is distributed to partners of the Company in accordance with their respective percentage interest in the Company. Additional excess cash flow distributions may be authorized to the Class A limited partners, which reduces their capital accounts. Rex Royalties distributed $49,073 and $103,467 in priority distributions and $886,000 and $322,500 in excess cash flow distributions for the years ended December 31, 2006 and 2005, respectively. At December 31, 2005, Rex Royalties accrued $300,000 of excess distributions that were paid in February 2006.

Hedging

The general partner, on behalf of the Company, has used commodity collars to manage price risk in connection with the sale of natural gas and accounts for those contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Results of natural gas derivative transactions are reflected in operating revenue.

The Company establishes the fair value of all derivative instruments using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, time to maturity, and credit risk. The values reported in the Company’s financial statements change as these estimates are revised to reflect actual results, changes in market conditions, or other factors.

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REX ENERGY ROYALTIES LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

SFAS No. 133 establishes accounting and reporting standards requiring derivative instruments (including certain derivative instruments embedded in other contracts or agreements) to be recorded at fair value and included in the Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in natural gas sales. For derivative instruments designated as fair value hedges (in accordance with SFAS No. 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Hedge effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time.

Royalty Revenue Recognition

All of the Company’s royalty revenue consists of royalties earned from natural gas wells owned by Douglas Westmoreland Limited Partnership, an affiliate of the Company (“Douglas Westmoreland”). The Company’s royalty revenue is earned as natural gas is delivered, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. At year-end, a royalty receivable of $58,038 and $413,734, relating to royalties earned on 2006 and 2005 production, respectively, is due to the Company from Douglas Westmoreland. The Company uses the allowance method to account for uncollectible accounts receivable. At December 31, 2006 and 2005, management determined there was no allowance for doubtful accounts.

Royalty Interests in Proved Development Properties

Rex Royalties uses the successful efforts method of accounting for their royalty interest in natural gas properties. The royalty interests in proved developed properties are depleted using the units-of-production method. All royalty interests in development properties relate to proved reserves. Depletion expense for December 31, 2006 and 2005 is $123,249 and $80,747, respectively.

The Company has evaluated the carrying value of its long-lived assets, consisting of royalty interests associated with natural gas producing properties, in order to determine whether the carrying value of such properties should be reduced. Management has determined that no adjustments to the carrying value of the assets are necessary as of December 31, 2006 and 2005.

Cash and Cash Equivalents

Rex Royalties considers all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

Accounting Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Accordingly, actual

F-288

REX ENERGY ROYALTIES LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

results could differ from those estimates. Among the more sensitive of the estimates involves determining the proved reserves from which depletion expense is calculated and determining the future net cash flows from which asset impairment, if any, is ascertained.

Income Taxes

Rex Royalties is treated as a partnership for federal and state income tax purposes. Accordingly, income taxes are not reflected in the financial statements because the resulting profit or loss is included in the income tax returns of the individual partners.

Natural Gas Reserve Quantities

The Company’s estimate of proved reserves is based on the quantities of natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell, and Associates, Inc. prepares a reserve and economic evaluation of all the Company’s royalty interests in properties on a lease-by-lease basis.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of the Company’s reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas and natural gas liquids eventually recovered.

New Accounting Pronouncements

On March 30, 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for the Company beginning January 1, 2005, and did not have a significant impact on the Company’s financial statements.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas

F-289

REX ENERGY ROYALTIES LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Producing Companies” and provides guidance about exploratory well costs to companies that use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling, and (3) an aging of exploratory well costs suspended for greater than one year with the number of wells it is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Application of this pronouncement did not have a significant impact on the Company’s financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,”, a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to

F-290

REX ENERGY ROYALTIES LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. The Company does not expect that adoption of this FASB Staff Position will have a material impact on its results of operations or financial position.

2. CONCENTRATION OF CREDIT RISKS

At times during the years ended December 31, 2006 and 2005, the Company’s cash balance may have exceeded the Federal Deposit Insurance Corporation’s insured limit of $100,000. There were no losses incurred due to concentrations.

3. HEDGING ACTIVITIES

The Company’s results of operations and operating cash flows are impacted by changes in market prices for natural gas. To mitigate a portion of the exposure to adverse market changes, the general partner of the Company may from time to time cause the Company to enter into natural gas hedges. During the year ended December 31, 2005, the Company’s natural gas derivative instruments consisted of collars. These instruments allowed it to predict with greater certainty the effective natural gas price to be received for the Company’s hedged production.

Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Rex Royalties receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

Rex Royalties incurred net payments of $23,195 under these collars during the year ended December 31, 2005 which reduced natural gas sales. All natural gas hedging activities matured as of December 31, 2005. There are no open positions as of December 31, 2006 and 2005.

4. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments.

F-291

REX ENERGY ROYALTIES LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

5. RELATED PARTY TRANSACTIONS

The Company reimburses the general partner for reasonable business expenses incurred in the operation of the Company such as legal fees, accounting fees, travel expenses, postage, photocopy charges, and other third party costs and expenses. At December 31, 2006 and 2005, the Company was indebted to the general partner in the amount of $3,239 and $10,374 respectively, for such expenses.

As of December 31, 2006 and 2005, the Company is due $11,516 and $3,683 from related parties, respectively. At year-end, a royalty receivable of $58,038 and $413,734, relating to royalties earned on 2006 and 2005 production, respectively, is due to the Company from Douglas Westmoreland.

The Company pays a management fee to Rex Energy Operating Corp. (owned by related individuals). The management fee expense for the years ended December 31, 2006 and 2005 was $18,192 and $28,007, respectively.

6. MAJOR CUSTOMERS

All of the natural gas extracted from wells in which the Company owns royalty interests is sold to Dominion Exploration and Production, Inc. or Dominion Peoples, Inc.

7. COSTS INCURRED IN NATURAL GAS ACQUISITION AND DEVELOPMENT ACTIVITIES

The Company did not incur costs associated with natural gas property acquisitions and developments for the years ended December 31, 2006 and 2005.

8. NATURAL GAS CAPITALIZED COSTS

The Company has capitalized $1,500,000 of costs related to royalty interests in natural gas properties and is presented net of accumulated depletion of $258,162 and $134,914 at December 31, 2006 and 2005.

9. RESULTS OF NATURAL GAS PRODUCING ACTIVITIES

Royalty revenue is derived from the natural gas production at wells located in Westmoreland County, Pennsylvania. The Company’s results of such activities are presented below:

	2006		2005			2004
Revenue
Royalty Revenue	$	686,238	$	790,720		$	404,478
Realized Gains (Losses) on Hedges		0		(23,195	)		(31,645	)
Net Revenue		686,238		767,525			372,833
Expenses
Depletion Expense		123,249		80,747			54,166
Total Expenses		123,249		80,747			54,166
Results for Natural Gas Producing Activities	$	562,989	$	686,778		$	318,667

F-292

REX ENERGY ROYALTIES LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

10. NATURAL GAS RESERVE QUANTITIES (UNAUDITED)

Independent engineers, Netherland, Sewell, and Associates, Inc., have evaluated the Company’s royalty interests in the proved reserves of the natural gas wells owned by Douglas Westmoreland and located in Westmorland County, Pennsylvania.

The Company emphasizes that reserve estimates are inherently imprecise. Its natural gas reserve estimates of wells located in Westmorland County, Pennsylvania were generally based upon extrapolation of historical production trends, analogy to similar properties, and volumetric calculations. Accordingly, these estimates are expected to change. These changes could be material and occur in the near term as information becomes available.

Proved natural gas reserves represent the estimated quantities of natural gas which geological and engineering data demonstrate with reasonable accuracy to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional gas expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

Presented below is a summary of changes in Rex Royalties’ interest in the estimated proved reserves of the natural gas wells located in Westmoreland County, Pennsylvania.

	Natural Gas (mcf)
December 31, 2006
Proved Reserves—Beginning of Period	844,655
Extensions, Discoveries, and Other Additions	67,969
Revisions of Previous Estimates	(58,406	)
Production	(51,212	)
Proved Reserves—End of Period	803,006
Proved developed reserves
December 31, 2005	696,374
December 31, 2006	629,994

11. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

Statement of Financial Accounting Standard No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proven reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of natural gas to be produced. Actual future prices and costs may be

F-293

REX ENERGY ROYALTIES LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0 percent annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth the Company’s future net cash flows relating to proved natural gas reserves based on the standardized measure prescribed by SFAS 69 for the year ended December 31, 2006:

Future Cash Inflows	(a)    4,910,382
Net Future Cash Inflows	4,910,382
Less Effect of a 10.0 Percent Discount Factor	(2,548,582	)
Standardized Measure of Discounted Future Net Cash Flows	$     2,361,800

(a) Calculated using weighted average prices of $6.11 per mcf of natural gas.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows for the year ended December 31, 2006:

Standardized Measure—Beginning of Period	$	4,260,900
Sales of Natural Gas Produced—Net of Production Costs		(405,491	)
Net Changes in Prices and Production Costs		(1,832,624	)
Extension and Discoveries		199,910
Revisions of Previous Quantity Estimates		(172,730	)
Accretion of Discount		426,090
Timing of Future Cash Flows and Other		(114,255	)
Standardized Measure—End of Period	$	2,361,800

F-294

Rex Energy Operating Corp.

F-295

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders of

Rex Energy Operating Corp.

State College, Pennsylvania

We have audited the accompanying balance sheets of the Rex Energy Operating Corp. as of December 31, 2006 and 2005 and the related statements of operations, stockholders’ equity (deficit) and cash flows for the year ended December 31, 2006 and for the period from inception to December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rex Energy Operating Corp. as of December 31, 2006 and 2005, and the results of its operations and its cash flows for the year ended December 31, 2006 and for the period from inception to December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.

Pittsburgh, Pennsylvania

March 15, 2007

F-296

REX ENERGY OPERATING CORP.

BALANCE SHEETS

	December 31,
	2006			2005
ASSETS
CURRENT ASSETS
Cash	$	26,490		$	160,297
Receivable from Employees		97,485			253,213
Related Party Receivable		87,026			138,370
Accounts Receivable		52,471			0
Prepaid Expenses		63,519			71,352
TOTAL CURRENT ASSETS		326,991			623,232
FIXED ASSETS
Leasehold Improvements		407,000			0
Vehicles and Equipment		724,354			76,790
Less: Accumulated Depreciation		(117,545	)		(6,301	)
FIXED ASSETS—NET		1,013,809			70,489
INVESTMENT IN NEW ALBANY-INDIANA, LLC (Note 12)		0			1,715,000
RESTRICTED CASH		46,747			45,000
TOTAL ASSETS	$	1,387,547		$	2,453,721
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES
Accounts Payable	$	200,209		$	296,835
Related Party Payable		449,652			302,445
Incentive from Lessor—Current Portion		47,448			0
Due to Lance Shaner (Note 12)		0			1,715,000
Accrued Expenses		263,385			256,815
Loans Payable—Current Portion		275,518			4,641
TOTAL CURRENT LIABILITIES		1,236,212			2,575,736
NON-CURRENT LIABILITIES
Loans Payable		242,890			25,902
Incentive from Lessor—Long Term Portion		83,034			0
TOTAL NON-CURRENT LIABILITIES		325,924			25,902
TOTAL LIABILITIES		1,562,136			2,601,638
STOCKHOLDERS’ DEFICIT
Capital Stock; 3,000 Shares Authorized, 100 Shares Issued and Outstanding—Par Value $1.00		100			100
Accumulated Deficit		(174,689	)		(148,017	)
TOTAL STOCKHOLDERS’ DEFICIT		(174,589	)		(147,917	)
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT	$	1,387,547		$	2,453,721

SEE ACCOMPANYING NOTES.

F-297

REX ENERGY OPERATING CORP.

STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2006		2005
OPERATING REVENUE
Management Fees from Affiliates	$	7,455,521	$	6,355,752
Other Operating Income From Affiliates		498,589		48,707
Other Operating Income		68,154		0
Interest Income		1,747		0
TOTAL OPERATING REVENUE		8,024,011		6,404,459
OPERATING AND GENERAL EXPENSES
Operating Expenses		7,820,778		6,443,791
Depreciation & Amortization Expense		111,245		6,301
Interest Expense		26,993		2,384
TOTAL OPERATING AND GENERAL EXPENSES		7,959,016		6,452,476
NET INCOME (LOSS)	$	64,995	$	(48,017	)

SEE ACCOMPANYING NOTES.

F-298

REX ENERGY OPERATING CORP.

STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)

YEARS ENDED DECEMBER 31, 2006 AND 2005

	Capital Stock		Stockholders’ Deficit
BEGINNING BALANCE—December 31, 2004	$	0	$	0
INCEPTION		100
DISTRIBUTIONS				(100,000	)
NET LOSS				(48,017	)
ENDING BALANCE—December 31, 2005	$	100	$	(148,017	)
DISTRIBUTIONS				(91,667	)
NET INCOME				64,995
ENDING BALANCE—December 31, 2006	$	100	$	(174,689	)

SEE ACCOMPANYING NOTES.

F-299

REX ENERGY OPERATING CORP.

STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	64,995		$	(48,017	)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Depreciation		111,245			6,301
Amortization of Lessor Incentive		(11,862	)		0
(Increase) Decrease in
Receivable from Employees		155,728			(253,213	)
Related Party Receivable		51,344			(138,370	)
Accounts Receivable		(52,471	)		0
Prepaid Expenses		7,833			(71,352	)
Restricted Cash Deposits		(1,747	)		(45,000	)
Increase (Decrease) in
Accounts Payable		(96,626	)		296,835
Accrued Expenses		6,570			256,815
Incentive from Lessor		142,344			0
Related Party Payable		147,207			302,445
NET CASH PROVIDED BY OPERATING ACTIVITIES		524,560			306,444
CASH FLOWS USED BY INVESTING ACTIVITIES
Leasehold Improvements		(407,000	)		0
Purchases of Vehicles and Equipment		(647,564	)		(76,790	)
NET CASH USED BY INVESTING ACTIVITIES		(1,054,564	)		(76,790	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Vehicle Loan		34,982			30,543
Proceeds from Loan for Copier		16,000			0
Proceeds for Enertia Loan		446,590			0
Proceeds for Building Loan		264,656			0
Repayment of Long Term Debts		(274,364	)		0
Capital Contribution		0			100
Distributions to Stockholders		(91,667	)		(100,000	)
NET CASH USED BY FINANCING ACTIVITIES		396,197			(69,357	)
NET INCREASE IN CASH		(133,807	)		160,297
CASH—BEGINNING		160,297			0
CASH—ENDING	$	26,490		$	160,297
SUPPLEMENTAL DISCLOSURES
Cash Paid for Interest	$	26,993		$	2,384
NON-CASH TRANSACTIONS
Repayments of Lance T. Shaner via Transfer of New Albany Interests	$	1,715,000		$	0

SEE ACCOMPANYING NOTES.

F-300

REX ENERGY OPERATING CORP.

NOTES TO FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006 AND 2005

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Organization

Rex Energy Operating Corp. (the “Company”) was organized on October 8, 2004, under the laws of the State of Delaware and began its primary operations on January 1, 2005 (business inception). The Company’s common shares are owned 60.0 percent by Lance T. Shaner, who serves as its Chairman and Chief Executive Officer, and 40.0 percent by Benjamin W. Hulburt, who serves as its President. The Company does not have any preferred stock issued or outstanding. The Company was organized for the purpose of managing oil and gas properties, and providing administrative and oil and natural gas field services to entities affiliated with the owners of the Company.

Revenue Recognition

The Company provides management services to affiliated companies in the oil and gas industry. The Company has entered into administrative services agreements, which provide for pre-determined fixed monthly management fees. The Company also acts as common paymaster for certain costs of the entities. Non-administrative costs incurred on behalf of the affiliates are billed to the affiliates at actual costs to the Company. Since the Company is the primary obligor of these costs, they are recorded as revenue and expenses of the Company. Revenue is recognized when services are provided. Management considers all amounts billed and receivable to be fully collectable.

Cash Equivalents

The Company considers investments in all highly liquid instruments with maturities of three months or less at date of purchase to be cash equivalents.

Fixed Assets

Fixed assets primarily include leasehold improvements, vehicles, office equipment, and computer hardware and software. Leasehold improvements include $142,344, received from Shaner Brothers, LLC (a related party) in 2006, as an incentive in the Company’s office space lease and are offset in liabilities as deferred rent. Leasehold improvements are amortized over the shorter of their estimated useful lives or the related lease life of three years. The Company has used the original lease term, excluding renewal option periods to determine useful life. Deferred rent is being amortized to general and administrative expense over the same term as leasehold improvements, which is three years. The remaining assets are being depreciated or amortized on a straight-line basis over their estimated useful lives of three to seven years.

Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Accordingly, actual results could differ from those estimates.

New Accounting Pronouncements

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires

F-301

REX ENERGY OPERATING CORP.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. We do not expect that adoption of this FASB Staff Position will have a material impact on our results of operations or financial position.

F-302

REX ENERGY OPERATING CORP.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

2. CONCENTRATION OF CREDIT RISKS

At times during the year ended December 31, 2006, the Company’s cash balance may have exceeded the Federal Deposit Insurance Corporation’s insured limit of $100,000. There were no losses incurred due to concentrations.

3. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments.

4. INCOME TAXES

No provision for income taxes is made in the Company’s financial statements because the Company has elected to be taxed under the provisions of Sub-Chapter S of the Internal Revenue Code. The Company’s income or loss is included in the income tax returns of the individual stockholders.

5. ADVERTISING EXPENSE

Advertising costs are expensed as incurred and equaled $38,516 and $22,571 for the years December 31, 2006 and 2005, respectively.

6. 401(K) PLAN

The Company sponsors a 401(k) Plan for its eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Company contributions to the plan are discretionary. Company contributions to the plan were $184,782 and $108,800 for the years ended December 31, 2006 and 2005, respectively. The Company paid $8,255 and $4,462 of expenses on behalf of the 401(k) plan for the years ended December 31, 2006 and 2005, respectively.

F-303

REX ENERGY OPERATING CORP.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

7. LOANS AND NOTES PAYABLE

The Company has various loans and notes payable outstanding as of December 31, 2006 and 2005. The loans and notes payable consist of the following at December 31:

		2006		2005
a.	Vehicle Loan Payable	$	20,145	$	30,543
b.	Vehicle Loan Payable		26,894		0
c.	Copier Loan Payable		12,741		0
d.	Enertia Software Note Payable		205,127		0
e.	Leasehold Improvement Note Payable		253,501		0
		$	518,408	$	30,543

a. This vehicle loan requires payments of principal and interest at 7.24 percent per annum equal to $694 per month. The loan matures in August 2009.

b. In April 2006, the Company obtained a vehicle loan in the amount of $34,982. This vehicle loan requires payments of principal and interest at 7.0 percent per annum equal to $1,082 per month. The loan matures in March 2009.

c. In May 2006, the Company obtained a loan to finance the purchase of copier equipment. This loan requires payments of principal and interest at 7.5 percent per annum equal to $499 per month. The loan matures in April 2009.

d. In February 2006, the Company acquired new oil and gas accounting software (“Enertia”) in the amount of $446,590. The Company financed this software with a note payable to the vendor. The Company made an initial down payment of $50,000 toward the note payable in March 2006. Beginning May 2006, this note payable requires payments of principal and interest at 7.5 percent per annum equal to $23,510 per month. The note payable matures in October 2007.

e. During 2006, the Company moved its headquarters to a 5,270 square foot building owned by Shaner Brothers, LLC (a related party). The Company financed the construction of leasehold improvements with a note payable to Shaner Brothers, LLC in the amount of $264,656. The note payable was effective in October 2006. The note payable requires payments of principal and interest at 7.0 percent per annum equal to $5,240 per month. The note payable matures in September 2011.

The five-year principal maturities for the Company’s loans and notes payable are as follows at December 31:

2007	$	275,518
2008		75,523
2009		64,073
2010		57,476
2011		45,818
Thereafter		0
Total Note Payable	$	518,408

F-304

REX ENERGY OPERATING CORP.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

8. LEASE COMMITMENTS

The Company has lease commitments for three different locations. Lease commitments by year for each of the next five years are as follows at December 31:

2007	$	142,048
2008		117,768
2009		63,264
Thereafter		0
Total	$	323,080

9. RELATED PARTY TRANSACTIONS

The Company receives substantively all of its revenue from companies engaged in the oil and gas industry, which are affiliated with the Company’s stockholders, Lance T. Shaner and Benjamin W. Hulburt. The Company has entered into administrative services agreements with these companies, each of which provide for the payment of a pre-determined monthly management fee and out-of-pocket direct expenses to the Company.

For the year ended December 31, 2006, the Company recognized $7,455,521 and $498,589 in management fees and other operating income from affiliates. For the year ended December 31, 2005, the Company recognized $6,355,752 and $48,707 in management fees and other operating income from affiliates. As of December 31, 2006 and 2005, the Company was due $87,026 and $138,370 from related parties, primarily related to management fees and other expenses owed from affiliates. As of December 31, 2006 and 2005, the Company owed $449,652 and $302,445 to related parties, primarily related to advances from affiliates.

Pursuant to an oral month-to-month lease agreement, the Company leased approximately 3,725 square feet of office space from Shaner Brothers, LLC at a fixed rental rate of $5,000 per month from inception of the Company until September 1, 2006. Shaner Brothers, LLC is a Pennsylvania limited liability company which is currently owned by Lance T. Shaner, a 60.0 percent shareholder of the Company, and Shaner Family Partners Limited Partnership, a Pennsylvania limited partnership controlled by Mr. Shaner (“Shaner Brothers”). On September 1, 2006 this oral month-to-month lease agreement terminated.

Beginning on September 1, 2006, the Company leased approximately 5,270 square feet of office space from Shaner Brothers. This office space is located at the Company’s current headquarters at 1975 Waddle Road, State College, Pennsylvania. The Company currently leases this office space pursuant to a written lease agreement that provides for an initial term of three years, expiring on August 31, 2009. The lease agreement requires the payment of rent in the amount of $7,908 per month, subject to adjustment on each anniversary date of the lease in accordance with the percentage of increase in the Consumer Price Index for the U.S. for Urban Consumers (CPI-U) for the preceding year (the “CPI Adjustment”). The monthly rent is also subject to adjustment in the form of additional monthly rent which is calculated annually and equal to the percentage of increase of Shaner Brother’s costs for taxes, insurance premiums and operating expenses for the previous year (the “Additional Monthly Rent”). The annual monthly rent adjustment resulting from the CPI Adjustment and Additional Monthly Rent may not in the aggregate exceed a three percent increase over the prior lease year. Under the terms of the lease, the Company is responsible for certain costs relating to the interior construction of the building and the payment of all utilities, cleaning expenses, maintenance and other related costs and expenses of the building resulting from the Company’s operation, use and occupancy of the premises. Following the expiration of the initial term, the Company may renew the lease for up to 3 one-year extensions upon written notice to Shaner

F-305

REX ENERGY OPERATING CORP.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

Brothers at least 120 days, but no more than 6 months, prior to the expiration of the current term. The Company believes that the terms of this lease are comparable to terms that could be obtained at an arms’ length basis in the State College, Pennsylvania area for leases of similar office space.

On September 1, 2006, Shaner Brothers loaned $264,656 to the Company to fund its expenses relating to the construction of the interior portions of its headquarters office building. This loan is evidenced by an unsecured promissory note dated September 1, 2006. The promissory note provides for the payment of interest on the unpaid principal sum at a rate of 7% per annum. The loan must be repaid in 60 consecutive equal monthly installments of principal and interest in the amount of $5,240. The promissory note matures on September 1, 2011, but may be prepaid in whole or in part at anytime, without premium or penalty. At December 31, 2006, the outstanding principal amount of the loan was $253,501. The Company believes that the terms of this loan are comparable to terms that could be obtained at an arms’ length basis from unrelated lenders.

The Company obtains certain administrative services (such as human resources, information technology, payroll, and tax services) from Shaner Solutions Limited Partnership, a Delaware limited partnership controlled by Lance T. Shaner (“Shaner Solutions”), pursuant to an oral month-to-month agreement providing for a monthly fee of $15,000, plus reimbursement for Shaner Solutions’ reasonable out-of-pocket expenses. The Company believes that the amount charged by Shaner Solutions is comparable to rates obtainable at an arm’s length basis in the State College, Pennsylvania area for similar services.

The Company has an oral month-to-month agreement with Charlie Brown Air Corp., a New York corporation owned by Lance T. Shaner (“Charlie Brown”), regarding the use of two airplanes owned by Charlie Brown. Under the Company’s agreement with Charlie Brown, the Company pays a monthly fee for the right to use the airplanes equal to its percentage (based upon the total number of hours of use of the airplanes by the Company) of the monthly fixed costs for the airplane, plus a variable per hour flight rate of $1,350 per hour. The Company believes that the terms of this agreement are comparable to terms that could be obtained at an arms’ length basis in the State College, Pennsylvania area for similar private aircraft services.

10. EMPLOYEE RECEIVABLES

Receivables from employees as of December 31, 2005 were $253,213. Of this amount, $155,222 represents advances to employees so they could purchase oil and gas properties associated with Rex Energy II Limited Partnership. All of the amounts advanced to purchase properties were repaid in 2006.

The remaining balance of $97,991 at December 31, 2005 represents the outstanding balance on other loans to three employees. These loans are in the form of prepaid compensation. A total of $130,000 was loaned to these three employees in 2005. The loans are forgiven if the employees continue to be employed by the Company over periods ranging from 3 to 5 years. The loans will be expensed over the 3 to 5 year service terms. If the employee’s employment with the Company is terminated for any reason, the outstanding balance of the loan is immediately due and payable. In 2006 and 2005, the expense recognized for the portion of the loan forgiven was $32,667 and $32,667, respectively. The balance of these loans was $64,667 at December 31, 2006.

Employee receivables at December 31, 2006 also include $32,817 for amounts advanced to fund employees’ health savings accounts, which will be repaid through payroll withholdings throughout the year.

F-306

REX ENERGY OPERATING CORP.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

11. OTHER CONCENTRATIONS RISKS AND CONTINGENCIES

Substantively all revenue and receivables are from related entities involved in the oil and gas business. Those entities are subject to various market and environmental risks associated with the oil and gas industry. Management knows of no significant probable or possible environmental contingent liabilities.

12. INVESTMENT IN NEW ALBANY-INDIANA, LLC

On November 25, 2005, the Company entered into a joint venture with Baseline Oil & Gas Corp., a Nevada corporation (“Baseline”) for the purpose of acquiring working interests in leasehold acreage in the Illinois Basin located in Southern Indiana known to contain New Albany Shale formations. Under this joint venture, the Company, Rex Energy Wabash, LLC, and Baseline formed New Albany-Indiana, LLC, a Delaware limited liability company (“New Albany”). At the time of formation of New Albany, Baseline had a 50.0 percent membership interest, the Company had a 49.0 percent membership interest, and Rex Energy Wabash, LLC had a 1.0 percent membership interest. Rex Energy Wabash, LLC serves as the managing member of New Albany. There was no operating activity in New Albany in 2005 except for the payment of a deposit by New Albany for the purchase of leasehold interests in oil and gas properties located in the Illinois Basin. There was no income or expense in New Albany in 2005.

The Company’s capital contribution to New Albany was $1,715,000, which was borrowed from Lance T. Shaner. The loan did not have a repayment term or require interest. On January 30, 2006, the Company withdrew as a member from New Albany and assigned its membership interests to several of its related parties, namely Lance T. Shaner, Shaner & Hulburt Capital Partners Limited Partnership, Rex Energy II Limited Partnership, Douglas Oil & Gas Limited Partnership and Rex Wabash, LLC (collectively the “LLC Assignees”). Following the transfer to the LLC Assignees, Baseline continued to own a 50.0 percent membership interest in New Albany and the LLC Assignees together owned a 50.0 membership interest in New Albany. Of the LLC Assignees’ membership interest, Rex Wabash, LLC, a Delaware limited liability company, owns 1.0 percent and is the managing member of New Albany. The Company’s assignment of a 23.0287 percent membership interest in New Albany to Lance T. Shaner satisfied the loan made by Lance T. Shaner to the Company.

13. INCENTIVE FROM LESSOR

The Company adopted FASB Technical Bulletin 88-1, Issues Relating to Accounting for Leases, to account for a landlord incentive allowance in an operating lease. The Company, as the lessee, entered into an operating lease in which the Shaner Brothers, LLC (lessor) offered a $142,344 incentive allowance towards the cost of the Company making leasehold improvements.

In accordance with FASB Technical Bulletin 88-1, Issues Relating to Accounting for Leases, the $142,344 allowance is reported by the lessee as a liability and amortized straight line over the lease term as a reduction of rent expense. The lease term is three years. The total amortization for year ended December 31, 2006 that reduced rent expense is $11,882.

14. LITIGATION

EPA Matter

In September 2006, the United States Department of Justice (“U.S. DOJ”) and the United States Environmental Protection Agency (“U.S. EPA”) initiated an enforcement action against the Company and PennTex Resources Illinois, Inc. (“PennTex Illinois”), a Delaware corporation owned by the Company’s

F-307

REX ENERGY OPERATING CORP.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

stockholder, Lance T. Shaner, seeking mandatory injunctive relief and potential civil penalties based on allegations that the companies were violating the Clean Air Act in connection with the release of hydrogen sulfide (H2S) gas and other volatile organic compounds (“VOC’s”) in the course of the PennTex Illinois’ oil operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. The Company’s senior management and representatives of the U.S. EPA, U.S. DOJ, Illinois Environmental Protection Agency (“Illinois EPA”) and the Agency for Toxic Substances and Disease Registry (“ATSDR”) attended a meeting at the offices of the U.S. EPA in Chicago, Illinois on September 7, 2006, to discuss matters relating to the enforcement action. This meeting had been preceded by certain monitoring of air emissions in the areas surrounding Bridgeport, Illinois and Petrolia, Illinois that the U.S. EPA and ATSDR had conducted in May 2006.

As a result of the initial meeting with the government on September 7, 2006, and certain subsequent meetings and communications between the Company’s senior management and the U.S. EPA and U.S. DOJ, the Company and PennTex Illinois executed a non-binding agreement in principle with the U.S. EPA effective October 24, 2006. In the agreement in principle, the Company and PennTex Illinois agreed to develop and carry out a written response plan designed to further reduce possible emissions of H2S and VOC’s from the PennTex Illinois’ oil wells and facilities in the Lawrence Field that are closest to populated areas. The Company and PennTex Illinois agreed to operate and maintain the control measures described in the response plan in accordance with a written operations and maintenance plan to be developed by the companies and approved by the U.S. EPA. The agreement in principle also required the companies to evaluate the effectiveness of the control measures in the Lawrence Field installed pursuant to the response plan through a monitoring program, and required the companies to evaluate the need for additional control measures at other facilities within the Lawrence Field within 60 days. The companies also agreed to present to the U.S. EPA any recommendations for further action the companies might develop based upon their observations of the effectiveness of the control measures. The Company, PennTex Illinois and the U.S. EPA each agreed that they would use their best efforts to negotiate a proposed final settlement agreement that would resolve the government’s enforcement action, which settlement agreement would be published in the Federal Register and made subject to public comment prior to any final approval.

The senior management of the Company and PennTex Illinois and the U.S. EPA and U.S. DOJ are negotiating the terms of a comprehensive consent decree in which the Company and PennTex Illinois, without any admission of wrongdoing or liability and without any agreement to pay any civil fine or penalty, would agree to install certain control measures and to implement certain operating and maintenance procedures regarding the PennTex Illinois’ oil operations in the Lawrence Field. Under the terms of the proposed consent decree, the companies would also agree to establish a monitoring protocol that would be designed to facilitate the reduction of possible emissions of H2S and VOC’s from the PennTex Illinois’ operations near Bridgeport, Illinois and Petrolia, Illinois. While at this time the Company is unable to predict with certainty the outcome of this enforcement action and the final terms and conditions of the consent decree, it believes that the Company will be able to reach a final settlement with the government agencies. The Company also believes that the consent decree will not require the Company or PennTex Illinois to pay any civil fine or penalty, although it will provide for the possible imposition of specified daily fines and penalties for any days in which it might be determined that the companies have violated the terms and conditions of the consent decree. Any proposed consent decree will ultimately require the approval of a court of proper jurisdiction.

The Company intends to vigorously defend itself in this matter. In the event that the parties are unable to agree upon the final terms of the consent decree or if the consent decree is not ultimately approved by a court of proper jurisdiction, the Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable.

F-308

REX ENERGY OPERATING CORP.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

Leib Case

The Company and PennTex Illinois are defendants in a putative class action lawsuit that has been filed in the United States District Court for the Southern District of Illinois, Cause Number 3:06-CV-00802-JPG-CJP, styled “Julia Leib, et al. v. Rex Energy Operating Corp., et al.” This action was commenced on October 17, 2006, by plaintiffs, Julia Leib and Lisa Thompson, individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport, Illinois and Petrolia, Illinois. The complaint asserts that the operation of oil wells that are controlled, owned or operated by the Company and PennTex Illinois has resulted in “serious contamination” of the class area with H2S. The complaint asserts several causes of action, including violation of the Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct. The complaint seeks, among other things, injunctive relief under the Illinois Environmental Protection Act and Illinois common law, compensatory and other damages, punitive damages, and attorneys’ fees and costs. In addition, the complaint seeks the creation of a court-supervised, defendant-financed fund to pay for medical monitoring for the plaintiffs and others in the class area.

On November 14, 2006, the Company and PennTex Illinois filed a joint answer to the complaint specifically denying virtually all of the allegations in the complaint and asserting affirmative defenses thereto. On December 20, 2006, the plaintiffs filed a motion for class certification requesting that the court certify the case as a class action. The Company intends to vigorously oppose the plaintiffs’ motion for certification of the case as a class action.

Pursuant to the terms of a pollution liability policy with Federal Insurance Company, the Company has insurance coverage for possible damages relating to claims made in this lawsuit for up to $1,000,000. In addition, in accordance with the terms of the pollution liability policy, Federal Insurance Company has agreed to conduct the Company’s defense in this lawsuit at the insurer’s expense. Under the terms of a written agreement with the Company, Federal Insurance Company has agreed to pay a substantial portion of the Company’s costs and expenses relating to the defense of this lawsuit, including attorneys’ fees. Under the terms of the agreement, the Company is required to pay the costs and expenses relating to the defense in excess of the amounts payable by Federal Insurance Company.

The Company intends to vigorously defend against the claims that have been asserted against it in this lawsuit. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or the range of potential loss should the outcome be unfavorable.

15. SUBSEQUENT EVENTS

On January 26, 2007, the United States District Court for the Southern District of Illinois, in the case of the putative class action lawsuit filed against the Company and PennTex Illinois (See Note 14), issued a scheduling and discovery order establishing deadlines for completing discovery and briefing relating to the plaintiffs’ motion for class certification. The order states that after the filing of the last brief on class certification issues on August 31, 2007, the court will schedule a hearing on plaintiffs’ motion for class certification. The Company intends to vigorously oppose the plaintiffs’ motion for certification of the case as a class action. On January 31, 2007, the plaintiffs in the above action filed a motion for leave seeking permission to file an amended complaint that would add a claim against the defendants for alleged violation of Section 7002(a)(1) of the Resource Conservation And Recovery Act (“RCRA”). Plaintiffs’ proposed amended complaint makes factual allegations similar to those previously asserted in Plaintiffs’ prior pleadings. The Company believes that it is likely that the court will grant Plaintiffs’ leave to file the amended complaint. On February 6, 2007, the court set a final pretrial

F-309

REX ENERGY OPERATING CORP.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

conference for this case for August 7, 2008. The case is scheduled for jury trial on August 18, 2008, in the United States District Court for the Southern District of Illinois located in Benton, Illinois. The parties to this lawsuit have exchanged initial pretrial disclosures as required under the applicable rules and each side has served and responded to pre-deposition written discovery. The Company intends to vigorously defend against the claims that have been asserted against it in this lawsuit. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or the range of potential loss should the outcome be unfavorable to it.

F-310

PennTex Resources, L.P.

F-311

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

PennTex Resources, L.P.

State College, Pennsylvania

We have audited the accompanying balance sheets of PennTex Resources, L.P. as of December 31, 2006 and 2005 and the related statements of operations, changes in partners’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PennTex Resources, L.P. as of December 31, 2006 and 2005, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 17 to the financial statements, the Company restated its previously issued 2005 financial statements to correct the reporting of hedge settlements and other items.

Pittsburgh, Pennsylvania

March 15, 2007

F-312

PENNTEX RESOURCES, L.P.

BALANCE SHEETS

	December 31,
	2006			2005
				Restated
ASSETS
CURRENT ASSETS
Cash	$	27,805		$	0
Restricted Cash (Collateral for Hedges)		0			500,000
Production Receivable		679,989			835,651
Related Party Receivable		399,496			241,193
Other Receivables		115,519			0
Oil Inventory		87,466			96,568
Prepaid Expenses and Other Assets		0			18,041
TOTAL CURRENT ASSETS		1,310,275			1,691,453
PROPERTY AND EQUIPMENT
Proved Developed Oil and Gas Properties		5,612,267			4,370,549
Less: Accumulated Depreciation and Depletion		(1,532,518	)		(978,623	)
NET PROPERTY AND EQUIPMENT		4,079,749			3,391,926
LOAN COSTS—NET OF AMORTIZATION		235,549			60,647
TOTAL ASSETS	$	5,625,573		$	5,144,026
LIABILITIES AND PARTNERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts Payable	$	189,896		$	689,663
Accrued Expenses		587,962			83,602
Line of Credit Facility		0			2,549,016
Related Party Payable		1,291,201			0
Related Party Payable—Lance T. Shaner		0			8,136,423
Financial Instruments Payable—Current Portion		873,909			3,128,178
TOTAL CURRENT LIABILITIES		2,942,968			14,586,882
OTHER LIABILITIES
Revolving Line of Credit		12,644,536			0
Asset Retirement Obligation		887,569			854,042
Financial Instruments Payable—Long-Term Portion		132,668			790,899
TOTAL OTHER LIABILITIES		13,664,773			1,644,941
TOTAL LIABILITIES		16,607,741			16,231,823
COMMITMENTS AND CONTINGENCIES (Note 5)
PARTNERS’ EQUITY (DEFICIT)		(10,982,168	)		(11,087,797	)
TOTAL LIABILITIES AND PARTNERS’ EQUITY (DEFICIT)	$	5,625,573		$	5,144,026

SEE ACCOMPANYING NOTES.

F-313

PENNTEX RESOURCES, L.P.

STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2006			2005			2004
				Restated			Restated
OPERATING REVENUE
Oil and Natural Gas Sales	$	9,464,024		$	11,446,404		$	9,962,408
Realized Loss on Hedges		(3,278,082	)		(3,013,045	)		(659,380	)
Unrealized Gainn (Loss) on Hedges		2,912,500			(2,551,546	)		(1,367,531	)
Service Fees and Other Income		0			62,099			0
TOTAL OPERATING REVENUE		9,098,442			5,943,912			7,935,497
OPERATING EXPENSES
Operating Expenses		5,126,786			6,098,273			5,088,592
Production Taxes		77,163			232,449			268,000
General and Administrative		744,919			701,548			263,160
Accretion Expense on Asset Retirement Obligation		78,972			78,041			90,001
Depreciation, Depletion, and Amortization		671,668			1,180,997			1,125,012
TOTAL OPERATING EXPENSES		6,699,508			8,291,308			6,834,765
INCOME (LOSS) FROM OPERATIONS		2,398,934			(2,347,396	)		1,100,732
OTHER INCOME AND (EXPENSE)
Interest Expense		(1,138,148	)		(233,661	)		(325,020	)
Interest Income		36,143			16,170			0
Other Income (Expense)		(27,723	)		0			(5,955	)
Gain on Sale of Oil and Gas Properties		0			1,203,528			617,697
TOTAL OTHER INCOME (EXPENSE)		(1,129,728	)		986,037			286,722
NET INCOME (LOSS)	$	1,269,206		$	(1,361,359	)	$	1,387,454

SEE ACCOMPANYING NOTES.

F-314

PENNTEX RESOURCES, L.P.

STATEMENTS OF CHANGES IN PARTNERS’ EQUITY (DEFICIT)

YEARS ENDED DECEMBER 31, 2006, 2005—RESTATED, AND 2004—RESTATED

	Total Partners’ Equity (Deficit)
BALANCE—December 31, 2003		1,961,576
DISTRIBUTIONS TO PARTNERS		(500,000	)
NET LOSS		1,387,454
BALANCE—December 31, 2004	$	2,849,030
ADDITIONAL CAPITAL CONTRIBUTION FROM
LANCE T. SHANER		400,000
DISTRIBUTIONS TO PARTNERS		(1,550,000	)
REDEMPTION OF LIMITED PARTNERSHIP
INTEREST OF TAYLOR (Note 11)		(11,425,468	)
NET LOSS		(1,361,359	)
BALANCE—December 31, 2005	$	(11,087,797	)
ADDITIONAL CAPITAL CONTRIBUTION FROM
LANCE T. SHANER		700,000
DISTRIBUTIONS TO PARTNERS		(1,863,577	)
NET INCOME		1,269,206
BALANCE—December 31, 2006	$	(10,982,168	)

SEE ACCOMPANYING NOTES.

F-315

PENNTEX RESOURCES, L.P.

STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2006			2005			2004
				Restated			Restated
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	1,269,206		$	(1,361,359	)	$	1,387,454
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion, and Amortization		671,668			1,180,997			1,125,012
Accretion Expense		78,972			78,041			90,001
Unrealized (Gain) Loss on Hedges		(2,912,500	)		2,551,546			1,367,531
Gain on Sale of Oil and Gas Properties		0			(1,203,528	)		(617,697	)
(Increase) Decrease in
Restricted Cash		500,000			(76,241	)		0
Production Receivables		155,662			338,882			(1,174,533	)
Related Party Receivable (Operating)		(158,303	)		(241,193	)		0
Other Receivables		(115,519	)		0			0
Inventory		9,102			3,262			(39,330	)
Prepaid Expenses		18,041			58,249			(76,290	)
Increase (Decrease) in
Accounts Payable		(499,767	)		97,237			227,521
Accrued Expenses		504,360			(605,201	)		653,115
Plugging Costs Incurred		(45,640	)		0			0
Related Party Payable		1,291,201			0			0
NET CASH PROVIDED BY OPERATING ACTIVITIES		766,483			820,692			2,942,784
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Sale of Assets		0			2,741,258			810,000
Project Advances		0			0			(140,248	)
Development of Oil Properties and Related Equipment		(1,241,342	)		(951,065	)		(2,398,998	)
NET CASH PROVIDED (USED) BY INVESTING ACTIVITIES		(1,241,342	)		1,790,193			(1,729,246	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Note Payable		0			0			5,601,741
Proceeds from Line of Credit Facility		12,644,536			0			0
Repayment of Related Party Financing		(8,136,423	)		0			0
Repayment of Debt		(2,549,016	)		(2,752,725	)		(5,521,295	)
Proceeds from Related Party Payable (Financing)		0			8,136,423			0
Payments of Financing Costs		(292,856	)		0			(67,500	)
Contribution from Partner		700,000			400,000			0
Cash Distributions to Partners and Redemptions		(1,863,577	)		(9,216,540	)		(500,000	)
NET CASH USED BY FINANCING ACTIVITIES		502,664			(3,432,842	)		(487,054	)
NET INCREASE (DECREASE) IN CASH		27,805			(821,957	)		726,484
CASH—BEGINNING		0			821,957			95,473
CASH—ENDING	$	27,805		$	0		$	821,957
SUPPLEMENTAL DISCLOSURES
Interest Paid	$	1,138,148		$	233,661		$	325,020
Non-Cash Transaction Disclosures
Distribution of Well to Lance T. Shaner	$	0		$	170,043		$	0
Redemption—Property Distribution	$	0		$	3,758,926		$	0

SEE ACCOMPANYING NOTES.

F-316

PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Description of Business

PennTex Resources, L.P., (the “Company”) a Texas limited partnership, was formed on November 12, 1997. The general partner of the Company, Penn Tex Energy, Inc., a Delaware corporation, owns a 1.0 percent interest in the Company and is owned 100.0 percent by Lance T. Shaner. At the formation of the Company, Lance T. Shaner and Thomas J. Taylor owned 59.0 percent and 40.0 percent of the Company, respectively, as the limited partners. In October 2005, Thomas J. Taylor’s 40.0 percent limited partner interest was redeemed by the Company in exchange for all the Company’s interests in certain properties and wells located in the states of Texas, Oklahoma, Arkansas, Louisiana, and New Mexico and $7,666,540 in cash (See Note 11). There are no significant assets, liabilities, or any other activity in Penn Tex Energy, Inc., except for its 1.0 percent interest in the Company.

The Company engages in the acquisition of ownership interests in oil and natural gas reserves located on proved developed properties. As of December 31, 2005, the Company had non-operated working interests in approximately 1,630 active wells. As of December 31, 2006, the Company had non-operated working interest in approximately 1,621 active wells. The Company owned interests in oil and gas wells located in Texas, Oklahoma, Arkansas, Louisiana, New Mexico, Indiana, and Illinois during 2005. As of December 31, 2006, the Company owned interest in oil wells located in Indiana and Illinois.

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

Restricted Cash

The restricted cash balance for 2005 represented an account maintained as collateral on the hedges.

Production Receivable

Production receivables correspond to approximately one month of oil and natural gas revenue earned but not received by the associated wells operator. The production receivable is valued at the actual subsequent cash receipt amount and does not bear interest. The Company assessed the financial strength of its operators and records bad debts as necessary. The Company does not have any off-balance sheet credit exposure related to its operators.

Inventory

Inventory consists of PennTex’s ownership interests in oil held in terminal tanks located in the field. The inventory is valued at cost.

Financial Instruments

The Company’s financial instruments consist of cash and restricted cash, commodity collars, fixed price swaps, production receivables, accounts payable, and a line of credit facility.

F-317

PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Revenue Recognition

Natural gas and oil revenue is recognized when the oil and natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. In each case it is the measurement of the purchaser that determines the amount of oil or gas purchased (although there are provisions for challenging these measurements if we believe the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil and natural gas production is at our applicable field gathering system; therefore, we do not incur transportation costs related to our sales of oil and natural gas production. The Company does not currently participate in any gas-balancing arrangements.

Hedging Activities

The Company mainly uses commodity collars and fixed price swaps to manage price risk in connection with the sale of oil and natural gas and accounts for those contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The results of the Company’s oil and natural gas hedging activities are reflected in the revenue section of the statements of operations.

The Company has established the fair value of all hedging instruments using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. Values reported by the Company in its financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

SFAS No. 133 establishes accounting and reporting standards requiring hedging activities to be recorded at fair value and included in the Balance Sheets as assets or liabilities. The accounting for changes in fair value of a hedging instrument depends on the intended purpose of the hedge and the resulting designation, which is established at the inception of a hedge. For hedging instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in earnings. For hedging instruments designated as fair value hedges (in accordance with SFAS No. 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Hedge effectiveness is measured annually based on the relative changes in fair value between the hedging contract and the hedged item over time. However, the Company’s evaluations are not documented, and as a result, it is recording changes on the derivative valuations through earnings.

Loan Costs

Loan costs consist of debt issuance costs that are amortized over the term of the related debt (See Note 3). The gross carrying amount of loan fees is $292,675 and $90,970 for the years ended December 31, 2006 and

F-318

PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

2005, respectively, and is presented net of the accumulated amortization of $57,126 and $30,323 for the years ended December 31, 2006 and 2005, respectively. Unamortized loan costs associated with the 2005 line of credit (See Note 3) were fully amortized during the year ended December 31, 2006.

Income Taxes

The Company is treated as a partnership for federal and state income tax purposes. Accordingly, income taxes are not reflected in the financial statements because the resulting profit or loss is included in the income tax returns of the individual partners.

Accounting Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Accordingly, actual results could differ from those estimates. Among the more sensitive of the estimates involves determining the proved reserves, costs to plug a well, and salvage values of equipment, from which the asset retirement obligation and depletion expense is calculated. Estimates are utilized to determine the fair market value of the Company’s hedges. Also, management’s estimates and assumptions to determine future net cash flows that ascertain asset impairment, if applicable, are subject to variation from actual results.

Reclassification

The prior year financial statements have been reclassified to conform to the current year presentation.

Oil and Gas Properties Depreciation and Depletion

The Company accounts for its oil and natural gas exploration and production activities under the successful efforts method of accounting.

Oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and natural gas properties. Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of oil and natural gas, are capitalized. Workover costs are expensed as incurred.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are

F-319

PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

The Company accounts for impairment under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Management determined that no adjustments to the unamortized capitalized cost were necessary as of December 31, 2006 and 2005.

Upon the sale or retirement of proved oil and natural gas property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain. Sales of the Company’s assets are more fully described in Note 8.

Asset Retirement Obligations

The Company accounts for its plugging liability in accordance SFAS No. 143, “Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS No. 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which the oil and natural gas well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of the Company’s oil and natural gas properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is reversed. The asset retirement obligation is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0 percent.

A summary of the asset retirement obligation is as follows at December 31:

	2006			2005
Beginning Balance—Asset Retirement Obligation	$	854,042		$	947,000
Plugging Costs Incurred		(45,640	)		0
Asset Retirement Obligation for New Wells		195			0
Relief of Obligation due to Sales and Redemption		0			(170,999	)
Current Year Accretion Expense		78,972			78,041
Total Asset Retirement Obligation	$	887,569		$	854,042

F-320

PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Natural Gas and Oil Reserve Quantities

The Company’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell, and Associates, Inc. prepare a reserve and economic evaluation of all the Company’s properties on a lease-by-lease basis.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The Company’s independent engineering firm adheres to the same guidelines when preparing their reserve reports. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas, natural gas liquids, and oil eventually recovered.

New Accounting Pronouncements

On March 30, 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for the Company beginning January 1, 2005, and was applied in estimating the asset retirement obligation at December 31, 2005.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies that use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling, and (3) an aging of exploratory well costs suspended for greater than one year with the number of wells it is related to. Further, the disclosures should describe the activities undertaken to evaluate the

F-321

PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Application of this pronouncement did not have a significant impact on the Company’s financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require or permit assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements

F-322

PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. The Company does not expect that adoption of this FASB Staff Position will have a material impact on its results of operations or financial position.

2. CONCENTRATIONS OF CREDIT RISK

At times during the year ended December 31, 2006, the Company’s cash balance may have exceeded the Federal Deposit Insurance Corporation’s insured limit of $100,000. There were no losses due to concentrations.

3. LINE OF CREDIT FACILITY

On December 14, 2004, the Company entered into a $50 million line of credit facility with Guaranty Bank. As of December 31, 2004, the total borrowing base under the line of credit was $6,000,000. The borrowing base was determined semi-annually by Guaranty Bank according to the provisions of the agreement. All of the Company’s oil and natural gas assets secured the line of credit. The line of credit was to mature in December 2007 and required interest on a floating rate of prime plus 1.25 percent, which was 8.5 percent at December 31, 2005. The ending balance as of December 31, 2005 on the line of credit was $2,549,016, which represented the determined borrowing base.

On January 19, 2006, the Company and PennTex Resources Illinois, Inc., as co-borrowers, entered into a revolving line of credit of up to $22,500,000 with Manufacturers and Traders Trust Company, as agent (the “Agent”) (the “M&T Loan”). The Borrowing Base for the M&T line of credit was $18,500,000, as of December 31, 2006. Interest on the line of credit accrues and is payable at a rate per annum equal to the base rate from time to time in effect, plus one percent (1.0%). The base rate is equal to the rate of interest per annum then most recently established by the Agent as its “prime rate”, which rate may not be the lowest rate of interest charged by the Agent to its borrowers. Interest is calculated on unpaid sums actually advanced and outstanding and only for the period from the date or dates of such advances until repayment. There are no principal payments due monthly. The borrowers are jointly and severally liable with respect to borrowings under the M&T Loan. Each borrower has guaranteed the full and timely payment by the other borrower of each and every obligation and liability of such other borrower to the lenders. In addition, borrowings under the loan are guaranteed by the co-borrowers’ sole owner, Lance T. Shaner. The M&T line of credit is secured by each of the borrowers’ assets and oil producing properties located in the states of Illinois and Indiana. Borrowings from the M&T line of credit were used to repay the $2,549,016 in borrowings of the Company under the revolving line of credit with Guaranty Bank, FSB, to repay an $8,136,423 loan from Lance T. Shaner, and to fund a distribution to Lance T. Shaner in the amount of $1,863,577. The line of credit matures on January 16, 2009. The interest rate on the line of credit as of December 31, 2006 was 9.25 percent and the ending balance was $14,944,536, of which, $12,644,536 is allocated to the Company.

As of December 31, 2006, the Company and PennTex Resources Illinois, Inc., as co-borrowers, were not in compliance with the negative covenant in their credit agreement requiring that their ratio of current assets to current liabilities, as defined in the credit agreement, be at lease 1.1:1. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarter of 2007.

4. HEDGING ACTIVITIES

The Company’s results of operations and operating cash flows are impacted by changes in market prices for oil natural gas. To mitigate a portion of the exposure to adverse market changes, the Company entered into oil

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NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

hedges. As of December 31, 2006, its oil hedging instruments consisted of collars and fixed price swaps. These instruments allow the Company to predict with greater certainty the effective oil price to be received for its hedged production.

Collars contain a fixed floor price (put) and ceiling price (call). The put options are purchased from the counterparty by the Company’s payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays the Company an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty by the Company’s receipt of a cash premium. If the market price is greater than the call strike price for a calculation period, then the Company pays the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.

The Company sells oil in the normal course of business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in oil sales. The Company enters into derivative instruments such as swap contracts to hedge a portion of its forecasted oil sales.

The Company incurred net payments of $3,278,082 and $3,013,045 under these hedges during the years ended December 31, 2006 and 2005, respectively, which reduced oil and natural gas sales. Unrealized gains and (losses) associated with these collars and swap contracts are included in earnings and amounted to $2,912,500 and ($2,551,546) for the years ended December 31, 2006 and 2005, respectively.

The following is a summary of the Company’s open asset/ (liability) hedging positions as of December 31, 2006:

Quantity	Notional Volume (Bls)	Period	Floor/ Put Price		Ceiling/ Call Price		Fixed Price		Fair Market Value
Swap Contracts	36,000	1/07–12/07	$	0	$	0	$	64.75	$	2,351
Collars	32,000	1/07–4/07	$	34.00	$	38.35	$	0		(777,379	)
Collars	56,000	5/07–12/07	$	50.00	$	70.34	$	0		(98,881	)
Total Current Portion	124,000									(873,909	)
Collars	28,000	1/08–7/08	$	62.00	$	70.00	$	0		(33,295	)
Collars	55,000	2/08–12/08	$	65.00	$	80.20	$	0		157,722
Collars	20,000	8/08–12/08	$	62.00	$	69.10	$	0		(33,247	)
Collars	59,500	1/09–7/09	$	62.00	$	67.80	$	0		(122,944	)
Collars	40,000	8/09–12/09	$	62.00	$	66.10	$	0		(100,904	)
Total Long -Term Portion	202,500									(132,668	)
Total Financial Instruments Payable	326,500								$	(1,006,577	)

5. COMMITMENTS AND CONTINGENCIES

Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. PennTex has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. It conducts periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are

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NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

expected to devote a significant amount of time directly to any remediation effort. Except as described below, management knows of no significant probable or possible environmental contingent liabilities.

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. Except as described below, the Company has not experienced any significant environmental liability and is not aware of any potential environmental issues or claims as of December 31, 2006.

At December 31, 2006, the Company’s Balance Sheet included reserves for the legal proceedings detailed below of $292,000. The accrual of reserves for legal matters is included in Accrued Expenses on the Balance Sheet. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional loss, the amount of which is not currently estimable, in excess of the amounts currently accrued with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in actual liability exceeding the estimated ranges of loss and the amounts accrued. Based on currently available information, the Company believes that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed current accruals by an amount that would have a material adverse effect on the consolidated financial position or results of operations of the Company, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

EPA Matter

The Company owns a 25.0 percent working interest in certain oil producing wells and related facilities and equipment located in the states of Illinois and Indiana (the “Illinois and Indiana Properties”). The operator of the Illinois and Indiana Properties is PennTex Resources Illinois, Inc. (“PennTex Illinois”), a Delaware corporation which is wholly owned by the Company’s sole limited partner and the sole stockholder of the Company’s general partner, Lance T. Shaner. PennTex Illinois owns a 26.0 percent working interest in the Illinois and Indiana Properties. Rex Energy Operating Corp., a Delaware corporation controlled by Lance T. Shaner (“Rex Operating”), provides certain management and administrative services to PennTex Illinois in the course of its operations of the Illinois and Indiana Properties. In September 2006, the United States Department of Justice (“U.S. DOJ”) and the United States Environmental Protection Agency (“U.S. EPA”) initiated an enforcement action against Rex Operating and PennTex Illinois seeking mandatory injunctive relief and potential civil penalties based on allegations that the companies were violating the Clean Air Act in connection with the release of hydrogen sulfide (H2S) gas and other volatile organic compounds (“VOC’s”) in the course of oil operations associated with the Illinois and Indiana Properties near the towns of Bridgeport, Illinois and Petrolia, Illinois. The senior management of PennTex Illinois and Rex Operating and representatives of the U.S. EPA, U.S. DOJ, Illinois Environmental Protection Agency (“Illinois EPA”) and the Agency for Toxic Substances and Disease Registry (“ATSDR”) attended a meeting at the offices of the U.S. EPA in Chicago, Illinois on September 7, 2006, to discuss matters relating to the enforcement action. This meeting had been preceded by certain monitoring of air emissions in the areas surrounding Bridgeport, Illinois and Petrolia, Illinois that the U.S. EPA and ATSDR had conducted in May 2006.

As a result of the initial meeting with the government on September 7, 2006, and certain subsequent meetings and communications between the senior management of PennTex Illinois and Rex Operating, on the one hand, and the U.S. EPA and U.S. DOJ, on the other, Rex Operating and PennTex Illinois executed a non-binding agreement in principle with the U.S. EPA effective October 24, 2006. In the agreement in principle, Rex Operating and PennTex Illinois agreed to develop and carry out a written response plan designed to further

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PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

reduce possible emissions of H2S and VOC’s from the oil wells and facilities that are closest to populated areas. Rex Operating and PennTex Illinois agreed to operate and maintain the control measures described in the response plan in accordance with a written operations and maintenance plan to be developed by the companies and approved by the U.S. EPA. The agreement in principle also required the companies to evaluate the effectiveness of the control measures in the Illinois and Indiana Properties installed pursuant to the response plan through a monitoring program, and required the companies to evaluate the need for additional control measures at other facilities within 60 days. The companies also agreed to present to the U.S. EPA any recommendations for further action the companies might develop based upon their observations of the effectiveness of the control measures. Rex Operating, PennTex Illinois and the U.S. EPA each agreed that they would use their best efforts to negotiate a proposed final settlement agreement that would resolve the government’s enforcement action, which settlement agreement would be published in the Federal Register and made subject to public comment prior to any final approval.

The senior management of Rex Operating and PennTex Illinois, on the one hand, and the U.S. EPA and U.S. DOJ, on the other, are negotiating the terms of a comprehensive consent decree in which Rex Operating and PennTex Illinois, without any admission of wrongdoing or liability and without any agreement to pay any civil fine or penalty, would agree to install certain control measures and to implement certain operating and maintenance procedures regarding Illinois and Indiana Properties. Under the terms of the proposed consent decree, the companies would also agree to establish a monitoring protocol that would be designed to facilitate the reduction of possible emissions of H2S and VOC’s from the operations near Bridgeport, Illinois and Petrolia, Illinois. While at this time the Company is unable to predict with certainty the outcome of this enforcement action and the final terms and conditions of the consent decree, it believes that Rex Operating and PennTex Illinois will be able to reach a final settlement with the government agencies. The Company also believes that the consent decree will not require Rex Operating, PennTex Illinois or the Company to pay any civil fine or penalty, although it will provide for the possible imposition of specified daily fines and penalties for any days in which it might be determined that Rex Operating or PennTex Illinois have violated the terms and conditions of the consent decree. Any proposed consent decree will ultimately require the approval of a court of proper jurisdiction.

The Company owns non-operated working interests in the same oil wells and related facilities operated by PennTex Illinois that are the subject of this enforcement action. While the Company is not the subject of this enforcement action, in the event that the Company does become a party to the enforcement action, the Company intends to vigorously defend itself in this matter. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss in this matter should the outcome be unfavorable.

Leib Case

Rex Energy and PennTex Illinois are defendants in a putative class action lawsuit that has been filed in the United States District Court for the Southern District of Illinois, Cause Number 3:06-CV-00802-JPG-CJP, styled “Julia Leib, et al. v. Rex Energy Operating Corp., et al.” This action was commenced on October 17, 2006, by plaintiffs, Julia Leib and Lisa Thompson, individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport, Illinois and Petrolia, Illinois. The complaint asserts that the operation of oil wells which are a part of the Illinois and Indiana Properties and that are controlled, owned or operated by Rex Operating and PennTex Illinois has resulted in “serious contamination” of the class area with H2S. The complaint asserts several causes of action, including violation of the Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct. The complaint seeks, among other things, injunctive relief under the Illinois

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PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Environmental Protection Act and Illinois common law, compensatory and other damages, punitive damages, and attorneys’ fees and costs. In addition, the complaint seeks the creation of a court-supervised, defendant-financed fund to pay for medical monitoring for the plaintiffs and others in the class area. On November 14, 2006, Rex Operating and PennTex Illinois filed a joint answer to the complaint specifically denying virtually all of the allegations in the complaint and asserting affirmative defenses thereto. On December 20, 2006, the plaintiffs filed a motion for class certification requesting that the court certify the case as a class action. Rex Operating and PennTex Illinois intend to vigorously oppose the plaintiffs’ motion for certification of the case as a class action.

The Company owns non-operated working interests in the same oil wells and related facilities operated by PennTex Illinois that are the subject of this lawsuit. The Company is not a party to the lawsuit and the Company intends to vigorously oppose any attempts to join it as a defendant in the lawsuit. In the event that the Company is joined as a defendant in this lawsuit, the Company intends to vigorously defend itself in this matter. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss in this matter should the outcome be unfavorable.

6. RELATED PARTY TRANSACTIONS

The Company, in accordance with the terms of an administrative service agreement, paid $180,000 and $320,100 in administrative, accounting, and tax preparation fees to Rex Energy Operating Corp. for the year ended December 31, 2006 and 2005, respectively.

PennTex Resources Illinois, Inc. is the operator of all the Company’s wells. The Company paid PennTex Resources Illinois, Inc. $957,770 and $817,239 for well overhead charges for the year ended December 31, 2006 and 2005, respectively.

The Company transferred ownership of a well recorded at $170,043 to Lance T. Shaner in 2005. This transfer reduced the related party payable due to Lance T. Shaner by an equal amount. There is no gain recorded by the Company on this distribution.

The Company repaid an outstanding debt to Lance T. Shaner in the amount of $8,136,423 during the year ended December 31, 2006.

The Company had related party receivables due from affiliates recorded for $399,496 and $241,193 at December 31, 2006 and December 31, 2005, respectively. The Company had related party payables of $1,291,201 at December 31, 2006 due primarily to the monthly payment of invoices processed on behalf of the Company by PennTex Resources Illinois, Inc.

See also Note 11.

7. PARTNERSHIP AGREEMENT

In accordance with the terms of the Company’s limited partnership agreement, allocations of income or loss and distributions are made in accordance with each partners’ percentage interest. The limited partnership agreement allows for priority distributions. Priority distributions are preferential distributions of cash flow to the partners equal to 10.0 percent per year or a proportional amount for any partial year, or the aggregate amount of the capital return of all partners as adjusted from time to time. The Company made priority distributions in the

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PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

amount of $0 and $1,550,000 for the years ended December 31, 2006 and 2005, respectively. During the year ended December 31, 2006, Lance T. Shaner made a $700,000 capital contribution to the Company and received a distribution of $1,863,577.

8. SALES OF INTERESTS IN OIL AND GAS PROPERTIES

In January 2005, the Company sold its interests in the Black Fork Creek oil and gas field located in Smith County, Texas for $2,971,400. The sale resulted in a gain on disposal of $1,203,528.

9. MAJOR CUSTOMER

The Company sold 100.0 percent of its production attributable to wells located in the Illinois basin to Countrymark Cooperative, LLP in 2006 and 2005.

10. FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The Company estimates the carrying value of its line of credit to approximate fair value due to the credit facility carrying a market rate of interest.

The fair value of the liability associated with the Company’s hedging instruments is $1,066,577 and $3,919,077 for the years ended December 31, 2006 and 2005, respectively. The fair value is based on valuation methodologies of the Company’s counterparty. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

11. PARTNERSHIP REDEMPTION

On October 17, 2005, the Company redeemed the 40.0 percent limited partnership interest of Thomas J. Taylor in the Company. The redemption price was paid, in part, in the form of a distribution to Mr. Taylor of all of the Company’s oil and gas producing properties in the states of Texas, Oklahoma, New Mexico, Arkansas, and Louisiana. The distribution of producing properties did not include the Company’s jointly-owned oil producing properties located in the states of Illinois and Indiana.

The value of the partnership redemption was initially $11,084,230. Of this amount, $7,666,540 was distributed to Thomas J. Taylor in the form of cash. A distribution of net book value of property in the initial amount of $3,417,758 was also made. Subsequent to the issuance of the 2005 financial statements, an error was discovered, as detailed in Note 17, relating to additional accounts payable that increased the net book value of assets redeemed by $341,168. The cash distribution was financed by a personal loan to the Company from Lance T. Shaner. This loan has no term, no interest rate, and no interest was paid. Proceeds from the loan were also used by the Company to make the cash distribution to Thomas J. Taylor and applied as a pay-down to the line of credit facility with Guaranty Bank.

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PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

12. COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION AND

DEVELOPMENT ACTIVITIES

Costs incurred by the Company in oil and natural gas property acquisitions and developments are presented below:

	2006		2005
Oil and Natural Gas Property Acquisition Costs	$	195	$	0
Development Costs		1,271,381		961,065
Total	$	1,271,576	$	961,065

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather oil and natural gas.

13. OIL AND NATURAL GAS CAPITALIZED COSTS

Aggregate capitalized costs for the Company related to oil and natural gas production activities with applicable accumulated depreciation and depletion are presented below:

	2006			2005
Proved Oil and Natural Gas Properties	$	5,612,267		$	4,370,549
Undeveloped Properties		0			0
Total		5,612,267			4,370,549
Less: Accumulated Depreciation and Depletion		(1,532,518	)		(978,623	)
Total	$	4,079,749		$	3,391,926

14. RESULTS OF OIL AND NATURAL GAS PRODUCING ACTIVITIES

The results of operations for oil and natural gas producing activities (excluding overhead and interest costs) are presented below:

	2006			2005			2004
Revenue
Oil and Natural Gas Sales	$	9,464,024		$	11,446,404		$	9,962,408
Realized Losses on Hedges		(3,278,082	)		(3,013,045	)		(659,380	)
Unrealized Gain (Loss) on Hedges		2,912,500			(2,551,546	)		(1,367,531	)
Net Oil and Natural Gas Sales		9,098,442			5,881,813			7,935,497
Expenses
Operating Expenses		5,126,786			6,098,273			5,088,592
Production Taxes		77,163			232,449			268,000
Accretion Expense on Asset Retirement Obligation		78,972			78,041			90,001
Depreciation and Depletion		553,894			1,129,599			1,096,786
Total Expenses		5,836,815			7,538,362			6,543,379
Results of Operations for Oil and Natural Gas Producing Activities	$	3,261,627		$	(1,656,549	)	$	1,392,118

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PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, and other production taxes. In addition, production costs include administrative expenses applicable to support equipment associated with these activities.

Depreciation, depletion, and amortization expense includes those costs associated with capitalization acquisitions and development costs, but does not include the depreciation applicable to support equipment.

There is no provision for income taxes because the Company is a nontaxable entity.

15. OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED)

The Company’s independent engineers, Netherland, Sewell and Associates, Inc., have evaluated the Company’s proved reserves associated with the oil wells located in Indiana and Illinois.

PennTex emphasizes that reserve estimates are inherently imprecise. The Company’s oil reserve estimates of wells were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

Proved oil and natural gas reserves represent the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by oil and natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil and natural gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

Presented below is a summary of changes in estimated reserves of the oil wells located in Illinois and Indiana at December 31, 2006:

	Oil (bls)
Proved Reserves—Beginning of Period	2,305,617
Plus/Minus Revisions of Previous Estimates	(217,408	)
Production	(153,356	)
Proved Reserves—End of Period	1,934,853
Proved developed reserves
December 31, 2005	2,094,539
December 31, 2006	1,581,385

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PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

16. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

Statement of Financial Accounting Standard No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proven reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0 percent annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth the Company’s future net cash flows relating to proved natural gas reserves based on the standardized measure prescribed by SFAS 69 at December 31, 2006:

Future Cash Inflows	(a) $	109,725,514
Future Production Costs		(67,235,742	)
Future Abandonment Costs		(2,007,724	)
Future Development Costs		(3,623,550	)
Net Future Cash Inflows		36,858,498
Less: Effect of a 10.0% Discount Factor		(13,336,521	)
Standardized Measure of Discounted Future Cash Flows	$	23,521,977

(a) Calculated using weighted average prices of $56.71 per barrel of oil.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

Standardized Measure—Beginning of Period	$	32,965,681
Sales of Natural Gas Produced—Net of Production Costs		(4,260,889	)
Development Costs Incurred		1,252,550
Changes in Future Development Costs		(581,143	)
Net Changes in Prices and Production Costs		(6,593,155	)
Revisions of Previous Quantity Estimates		(2,998,440	)
Changes in Timing and Other		1,328,374
Future Abandonment Costs		(887,569	)
Accretion of Discount		3,296,568
Standardized Measure—End of Period	$	23,521,977

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PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

17. RESTATEMENT OF PREVIOUSLY ISSED STATEMENTS DUE TO CORRECTIONS

The Company has restated its previously issued 2005 financial statements for matters related to the following previously reported items: production receivable, accounts payable, distributions, hedging settlements, and natural gas and oil sales. The accompanying financial statements for 2005 have been restated to reflect the corrections. The following is a summary of the restatements for 2005:

To adjust hedging activity to accrual basis	$	(215,130	)
To record additional production receivable	$	96,180
To record additional amounts capitalized through accounts payable and subsequently distributed to Tommy J. Taylor	$	0
Total Reduction in 2005 Earnings	$	(118,950	)

The effect on the Company’s previously issued 2005 financial statements are summarized as follows:

Balance Sheet as of December 31, 2005:

	Previously Reported			Increase (Decrease)			Restated
Production Receivable	$	739,471		$	96,180		$	835,651
Total Current Assets	$	1,595,273		$	96,180		$	1,691,453
Total Assets	$	5,047,846		$	96,180		$	5,144,026
Accounts Payable	$	68,775		$	620,888		$	689,663
Total Current Liabilities	$	13,965,994		$	620,888		$	14,586,882
Total Liabilities	$	15,610,935		$	620,888		$	16,231,823
Beginning Partners’ Equity Balance	$	2,913,620		$	(64,590	)	$	2,849,030
Redemption	$	11,084,300		$	341,168		$	11,425,468
Total Partners’ Deficit	$	(10,563,089	)	$	524,708		$	(11,087,797	)
Total Liabilities and Partners’ Deficit	$	5,047,846		$	96,180		$	5,144,026

Statement of Operations for the Year Ended December 31, 2005:

	Previously Reported			Increase (Decrease)			Restated
Natural Gas and Oil Sales	$	11,350,224		$	96,180		$	11,446,404
Realized (Loss) on Hedges	$	(2,797,915	)	$	215,130		$	(3,013,045	)
Total Operating Revenue	$	6,062,862		$	(118,950	)	$	5,943,912
(Loss) From Operations	$	(2,228,446	)	$	118,950		$	(2,347,396	)
Net (Loss)	$	(1,242,409	)	$	118,950		$	(1,361,359	)

18. LITIGATION

The Company is involved in an arbitration panel convened by the American Arbitration Association in Houston, Texas, Cause Number 70 180 Y 00437 06, styled “PennTex Resources, L.P. And Lance T. Shaner, Claimants v. ERG Illinois Holdings, Inc. And Scott Y. Wood, Respondents.” This is a binding arbitration proceeding that was commenced on June 21, 2006, by the Company and Lance T. Shaner (“Shaner”) against ERG Illinois Holdings, Inc. (“ERG Holdings”) and Scott Y. Wood (“Wood”) pursuant to the dispute resolution provisions of a stock purchase agreement that was entered into in January 2005 by Wood’s company, ERG Holdings, as “Seller” and the Company, as “Buyer” (the “2005 Stock Purchase Agreement”).

The principal claim in the arbitration proceeding is the Company’s and Shaner’s claim that ERG Holdings and Wood should be ordered to comply with a “release obligation” contained in the 2005 Stock Purchase

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PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Agreement that requires Wood, under certain designated circumstances, to dismiss or release the individual claims that he is prosecuting against Tsar Energy II, LLC (“Tsar”) and Richard M. Cheatham (“Cheatham”) in a lawsuit in the 334th Judicial District Court of Harris County, Texas, cause number 2004-39584, styled “ERG Illinois, Inc. And Scott Y. Wood v. Tsar Energy II, LLC And Richard M. Cheatham (the “Tsar Case”). The dispute in the Tsar Case centers around overhead fees charged by PennTex Illinois as operator of jointly-owned oil producing properties located in Illinois and Indiana in which the Company owns a 25.0 percent working interest (the “Illinois and Indiana Properties”). Tsar then owned a 49.0 percent non-operator working interest in the subject properties. PennTex Illinois (then known as ERG Illinois, Inc.) and its former owner, Wood, commenced this litigation in July 2004, by filing a petition against Tsar and its president, Cheatham, seeking, among other things, a declaratory judgment that PennTex Illinois, as the operator of the subject properties, was entitled to charge Tsar and the other non-operators their proportionate shares of a fixed monthly overhead charge of $300 for each producing well located within the North Lawrence Unit portion of the properties pursuant to the terms of a operating agreement relating to such unit. The Company became obligated to file this arbitration proceeding seeking to enforce Wood’s “release obligation” under the 2005 Stock Purchase Agreement, and to prosecute such proceeding diligently without compromise until final award, by reason of an agreement that PennTex Illinois and the Company entered into on March 2, 2006 with Tsar and Cheatham in order to resolve certain procedural issues relating to the Tsar Case.

The Company and/or Shaner have also filed the following additional claims in the arbitration proceeding in which the Company or Shaner seek an award of money damages from ERG Holdings: (a) Shaner, as the assignee of the “Buyer” under the 2005 Stock Purchase Agreement, has filed a claim against ERG Holdings, as the “Seller” under the 2005 Stock Purchase Agreement, seeking an award of $383,760, plus pre-award interest and attorneys’ fees, based on ERG Holdings’ alleged breach of its obligation to make an appropriate post-closing purchase price adjustment as required under the terms of Section 2.2(c)(D) of the 2005 Stock Purchase Agreement; (b) the Company has filed a claim against ERG Holdings seeking an award of approximately $20,000, plus pre-award interest and attorneys’ fees, based on ERG Holdings’ alleged breach of a contractual obligation, allegedly arising under Section 9.4(d) of the 2005 Stock Purchase Agreement, to return the original and all copies of a letter a credit posted by the Buyer under that agreement to secure its indemnity obligations described in Section 9.4, which breach is alleged to have wrongfully caused the Company to have had to unnecessarily incur an annual renewal fee to keep such letter of credit in force so as to prevent ERG Holdings from having the right to draw on it (The Company’s claim in this regard also seeks equitable and injunctive relief that would declare the letter of credit void and restrain ERG Holdings from attempting to draw on it.); and (c) The Company has filed a claim against ERG Holdings seeking an award of approximately $23,500 (which the Company believes is likely to be revised downward to approximately $2,500), plus pre-award interest and attorneys’ fees, based on ERG Holdings’ alleged breach of its obligation to make an appropriate pre-closing purchase price adjustment as required under the terms of Section 2.2(c)(C) of the 2005 Stock Purchase Agreement by failing to reflect in its final closing statement an existing liability owed to the owners of a net profits interest relating to certain leases within the Illinois and Indiana Properties.

In its pleading filed on January 22, 2007, ERG Holding and Wood have denied all of the Company’s and Shaner’s claims, and ERG Holdings has asserted a counterclaim against the Company based on its previously-asserted claim that it is entitled to a post-closing adjustment in the purchase price in its favor in the amount of $182,864.97. The arbitration panel of the American Arbitration Association has scheduled a final hearing in the arbitration proceeding for June 25-26, 2007.

The Company and Shaner intend to vigorously prosecute all of the claims asserted in the arbitration proceedings, including Shaner’s claim seeking a final purchase price closing adjustment in the amount of $383,760 in favor of Shaner as the assignee of the “Buyer” under the 2005 Stock Purchase Agreement. The

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PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

Company and Shaner will also vigorously defend ERG Holdings’ counterclaim seeking an award that would result in a final purchase price closing adjustment in the amount of $182,865 in favor of the “Seller” under the 2005 Stock Purchase Agreement. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter. However, given that it is extremely unlikely that the arbitration panel would allow either party to amend their respective final purchase price adjustment claims to increase the amounts sought therein, the Company believes that the amount of potential loss to the Company should the outcome be unfavorable would be no more than $182,865, plus pre-award interest on such sum.

The Company was involved in a civil lawsuit in United States District Court for the Southern District of Texas, Houston Division, Civil Action Number H-06-2198, styled “Scott Y. Wood v. PennTex Resources, L.P. And Lance T. Shaner.” This action was commenced on June 30, 2006, by Wood in an effort to obtain a declaratory judgment that he cannot be compelled to participate in the arbitration proceeding that the Company and Shaner had commenced on June 21, 2006, against ERG Holdings and Wood as described above. Wood is not a designated signatory party to the 2005 Stock Purchase Agreement described above, but is explicitly named as a beneficiary of a comprehensive set of indemnity provisions in that agreement that provided Wood and others with protection from liability in the Tsar Case. On August 1, 2006, the Company and Shaner responded to Wood’s complaint by filing an answer and counterclaim asserting that the action should be stayed, and that Wood should be compelled to proceed to arbitration in the pending arbitration proceeding notwithstanding that he was not a designated signatory party to the 2005 Stock Purchase Agreement that contains both the “release obligation” at issue and the dispute resolution provisions creating rights to seek binding arbitration with respect to issues relating to that Agreement. On October 23, 2006, the court issued a Memorandum And Order granting the Company’s and Shaner’s motion to compel arbitration. On November 2, 2006, in response to defendants’ joint motion in support of stay, rather than dismissal, the court signed an order staying the action and administratively closing it pending the final award in the underlying arbitration proceeding.

This action does not involve a claim against the Company for damages or any other form of monetary relief. The Company and Shaner vigorously defended this action, and used it as a procedural vehicle to compel Wood to participate in the pending arbitration proceeding described above. The Company does not believe that this action as presently constituted can result in any loss to the Company.

19. SUBSEQUENT EVENTS

On January 26, 2007, the United States District Court for the Southern District of Illinois, in the case of the putative class action lawsuit filed against Rex Operating and PennTex Illinois (See Note 5), issued a scheduling and discovery order establishing deadlines for completing discovery and briefing relating to the plaintiffs’ motion for class certification. The order states that after the filing of the last brief on class certification issues on August 31, 2007, the court will schedule a hearing on plaintiffs’ motion for class certification. Rex Operating and PennTex Illinois intend to vigorously oppose the plaintiffs’ motion for certification of the case as a class action. On January 31, 2007, the plaintiffs in the above action filed a motion for leave seeking permission to file an amended complaint that would add a claim against the defendants for alleged violation of Section 7002(a)(1) of the Resource Conservation And Recovery Act (“RCRA”). Plaintiffs’ proposed amended complaint makes factual allegations similar to those previously asserted in Plaintiffs’ prior pleadings. The Company believes that it is likely that the court will grant Plaintiffs’ leave to file the amended complaint. On February 6, 2007, the court set a final pretrial conference for this case for August 7, 2008. The case is scheduled for jury trial on August 18, 2008, in the United States District Court for the Southern District of Illinois located in Benton, Illinois. The parties to this lawsuit have exchanged initial pretrial disclosures as required under the applicable rules and each side has served and responded to pre-deposition written discovery.

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PENNTEX RESOURCES, L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

As of December 31, 2006, the Company and PennTex Resources Illinois, Inc., as co-borrowers, were not in compliance with the negative covenant in their credit agreement requiring that their ratio of current assets to current liabilities, as defined in the credit agreement, be at lease 1.1:1. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarter of 2007.

On February 28, 2007, the Company received a letter from counsel to ERG Holdings and Wood demanding that the Company and Shaner reimburse ERG Holdings and Wood for legal fees alleged to be incurred by the parties in connection with the Tsar Case in the amount of $171,351 (See Note 18). ERG Holdings and Wood contend that the 2005 Stock Purchase Agreement requires the Company and Shaner to reimburse them for all legal costs and expenses relating to the Tsar Case. The Company and Shaner contend that the 2005 Stock Purchase Agreement requires that the Company reimburse ERG Holdings and Wood for legal costs incurred in their defense of the Tsar Case, but that the Company is not required to pay any legal costs incurred by ERG Holdings and Wood in connection with the prosecution of Wood’s claims against Tsar, and that this arrangement for the payment of legal fees was previously orally agreed to by ERG Holdings and Wood. In the letter dated February 28, 2007, ERG Holdings and Wood stated that it in event that the Company and Shaner refuse to pay the claimed legal fees, ERG Holdings and Wood will add an additional counterclaim to the arbitration proceeding currently pending before the American Arbitration Association in Houston, Texas described in Note 18. On March 15, 2007, the Company paid $15,021 to ERG Holdings and Wood for legal costs incurred in their defense of the Tsar Case in January 2006. The Company believes that ERG Holdings and Wood are not entitled to any further reimbursement of legal costs incurred in their defense of the Tsar Case.

The Company and Shaner intend to vigorously oppose any attempts by ERG Holdings and Wood to add a counterclaim to the arbitration proceeding on the grounds that the panel imposed deadline for adding counterclaims has passed. In the event that the arbitration panel permits ERG Holdings and Wood to add the counterclaim, the Company and Shaner intend to vigorously defend themselves against the counterclaim. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter. The Company believes that the amount of potential loss to the Company should the outcome of the counterclaim be unfavorable would be no more than $156,330, plus pre-award interest on such sum.

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PennTex Resources Illinois, Inc.

F-336

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholder of

PennTex Resources Illinois, Inc.

State College, Pennsylvania

We have audited the accompanying balance sheets of PennTex Resources Illinois, Inc. as of December 31, 2006 and 2005 and the related statements of operations, changes in stockholder’s equity (deficit) and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PennTex Resources Illinois, Inc. as of December 31, 2006 and 2005, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 16 to the financial statements, the Company restated its previously issued 2005 financial statements to correct the reporting of well tubing inventory.

Pittsburgh, Pennsylvania

March 15, 2007

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PENNTEX RESOURCES ILLINOIS, INC.

BALANCE SHEETS

	December 31,
	2006			2005
				Restated
ASSETS
CURRENT ASSETS
Cash	$	6,951		$	0
Production Receivable		713,833			766,258
Joint Interest Billing Receivable—Net Allowance of $147,209		74,999			435,763
Stockholder Receivable		0			700,000
Other Receivables		128,252			0
Oil and Tubing Inventory		480,444			387,521
Related Party Receivables		1,580,098			0
Prepaid Expenses		126,300			19,173
TOTAL CURRENT ASSETS		3,110,877			2,308,715
PROPERTY AND EQUIPMENT
Proved Oil Properties		8,614,317			7,301,705
Wells-In-Progress		80,000			0
Field Operation Vehicles		578,855			568,867
Total Property and Equipment		9,273,172			7,870,572
Less: Accumulated Depreciation and Depletion		(1,652,006	)		(641,958	)
NET PROPERTY AND EQUIPMENT		7,621,166			7,228,614
FINANCIAL INSTRUMENTS—Long Term Portion		22,746			0
TOTAL ASSETS	$	10,754,789		$	9,537,329
LIABILITIES AND STOCKHOLDER’S DEFICIT
CURRENT LIABILITIES
Accounts Payable		2,013,959			2,433,375
Accrued Expenses		377,384			862,180
Accrued Distributions to Stockholder		0			3,100,000
Current Portion of Loan Payable—Vehicles		90,330			83,454
Loan Payable—Lance T. Shaner		1,820,000			0
Related Party Payable		0			317,894
Financial Instruments Payable—Current Portion		2,098,391			1,812,652
TOTAL CURRENT LIABILITIES		6,400,064			8,609,555
OTHER LIABILITIES
Asset Retirement Obligation		920,568			854,041
Vehcile Loan Payable		148,922			232,839
Line of Credit Facility		2,300,000			0
Financial Instruments Payable—Long-Term Portion		0			2,032,837
TOTAL OTHER LIABILITIES		3,369,490			3,119,717
TOTAL LIABILITIES		9,769,554			11,729,272
COMMITMENTS AND CONTINGENCIES (Note 6)
STOCKHOLDER’S DEFICIT
Common Stock—1,000 Shares Authorized, Issued, and Outstanding		1,000			1,000
Additional Paid-In Capital		1,460,000			1,460,000
Accumulated Deficit		(475,765	)		(3,652,943	)
TOTAL STOCKHOLDER’S DEFICIT		985,235			(2,191,943	)
TOTAL LIABILITIES AND STOCKHOLDER’S DEFICIT	$	10,754,789		$	9,537,329

SEE ACCOMPANYING NOTES.

F-338

PENNTEX RESOURCES ILLINOIS, INC.

STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2006			2005
				Restated
OPERATING REVENUE
Oil Sales	$	10,011,844			9,102,896
Realized Loss on Hedges		(2,110,677	)		(4,599,517	)
Unrealized Gain (Loss) on Hedges		1,769,844			(2,480,740	)
TOTAL OPERATING REVENUE		9,671,011			2,022,639
OPERATING EXPENSES
Operating Expenses		5,211,366			5,023,152
Production Taxes		34,562			78,301
General and Administrative (Income)		(99,965	)		397,365
Accretion Expense on Asset Retirement Obligation		82,681			77,640
Depreciation and Depletion		1,010,049			641,958
TOTAL OPERATING EXPENSES		6,238,693			6,218,416
INCOME (LOSS) FROM OPERATIONS		3,432,318			(4,195,777	)
OTHER INCOME (EXPENSE)
Interest Income		2,413			9,246
Interest Expense		(224,847	)		(118,118	)
Other Income (Expense)—Net		(32,706	)		8,688
TOTAL OTHER INCOME (EXPENSE)		(255,140	)		(100,184	)
NET INCOME (LOSS)	$	3,177,178		$	(4,295,961	)

SEE ACCOMPANYING NOTES.

F-339

PENNTEX RESOURCES ILLINOIS, INC.

STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY (DEFICIT)

YEARS ENDED DECEMBER 31, 2006 AND 2005—RESTATED

	Capital Stock		Additional Paid-In Capital		Retained Earnings (Deficit)			Total Stockholder’s Equity (Deficit)
BALANCE—January 1, 2005	$	1,000	$	0	$	4,502,282		$	4,503,282
EXCESS OF PURCHASE PRICE OVER NET ASSETS ACQUIRED				1,460,000					1,460,000
DISTRIBUTIONS						(3,859,264	)		(3,859,264	)
NET (LOSS)						(4,295,961	)		(4,295,961	)
BALANCE—December 31, 2005	$	1,000	$	1,460,000	$	(3,652,943	)	$	(2,191,943	)
DISTRIBUTIONS						0			0
NET INCOME						3,177,178			3,177,178
BALANCE—December 31, 2006	$	1,000	$	1,460,000	$	(475,765	)	$	985,235

SEE ACCOMPANYING NOTES.

F-340

PENNTEX RESOURCES ILLINOIS, INC.

STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2006			2005
				Restated
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	3,177,178		$	(4,295,961	)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Depreciation and Depletion		1,010,049			641,958
Accretion Expense		82,681			77,640
Bad Debt Expense		50,531			6,053
Unrealized (Gain) Loss on Hedges		(1,769,844	)		2,480,740
(Increase) Decrease in
Production and JIB Receivables		362,658			43,024
Related Party Receivables		(1,580,098	)		0
Other Receivables		(128,252	)		0
Inventory		(92,923	)		(261,999	)
Prepaid Expenses		(107,127	)		196,455
Increase (Decrease) in
Accounts Payable and Accrued Expenses		(904,212	)		2,725,091
Plugging Costs Incurred		(16,357	)		0
Related Party Payable		(317,894	)		317,894
NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES		(233,610	)		1,930,895
CASH FLOWS USED BY INVESTING ACTIVITIES
Development of Oil Properties and Related Equipment		(1,402,398	)		(420,657	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Working Capital Loans		0			1,400,000
Repayment of Working Capital Loans		0			(1,400,000	)
Proceeds from M&T Line of Credit		3,200,000			0
Repayment of M&T Line of Credit		(900,000	)		0
Proceeds from Related Party Loan Payable		1,820,000			0
Stockholder Receivables		700,000			(700,000	)
Distributions to Stockholders		(3,100,000	)		(759,264	)
Principal Payments on Loan Payable—Vehicle		(77,041	)		(50,974	)
NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES		1,642,959			(1,510,238	)
NET INCREASE IN CASH		6,951			0
CASH—BEGINNING		0			0
CASH—ENDING	$	6,951		$	0
SUPPLEMENTAL DISCLOSURES
Interest Paid	$	224,847		$	118,118
Non-Cash Transactions
Distributions	$	0		$	3,100,000
See Also Note 1—Acquisitions

SEE ACCOMPANYING NOTES.

F-341

PENNTEX RESOURCES ILLINOIS, INC.

NOTES TO FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006 AND 2005

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Description of Business

Lance T. Shaner acquired 100.0 percent of the common stock of ERG Illinois, Inc., a Delaware Corporation, (“ERG”), from ERG Holdings, Inc. (“ERG Holdings”) effective January 1, 2005. ERG was the operator of jointly-owned oil producing properties located in the states of Illinois and Indiana and has a corresponding 26.0 percent working interest in those properties. Following the acquisition of common stock, ERG was renamed to PennTex Resources Illinois, Inc. (“the “Company”). The total purchase price was $5,962,000. The transaction was accounted for as a purchase, and the excess of the purchase price over the ERG equity was pushed down to the Balance Sheet of PennTex Resources Illinois, Inc. The excess of the purchase price over the ERG reported equity of $1,460,000 was allocated to oil properties and reported as a credit to additional paid in capital. The Company also assumed the outstanding derivative liabilities (costless collars—see Note 3) of ERG. These derivatives had a fair value of $1,365,000 at the acquisition date of January 1, 2005. The Company recorded this liability at acquisition and recognized the amount as additional consideration of oil properties. The purchase price allocation was as follows:

Receivables	$	1,539,463
Allowance for Doubtful Accounts		(147,209	)
Prepaid Expenses and Other		215,628
Oil Inventory		125,522
Vehicles		199,000
Oil and Gas Properties		6,881,048
Payables		(562,124	)
Derivative Liability		(1,365,000	)
Asset Retirement Obligation		(924,000	)
Total	$	5,962,328

ERG Holdings is asserting a claim for an additional $182,865 as a final purchase price adjustment due from the Company’s sole stockholder, Lance T. Shaner (“Shaner”). Lance T. Shaner is asserting a claim for an additional $383,760 as a final purchase price adjustment due from ERG Holdings. These claims are each the subject of an arbitration panel proceeding before the American Arbitration Association. The arbitration panel has scheduled a final hearing in the arbitration proceeding for June 25 and 26, 2007 in Houston, Texas. In accordance with Statement of Financial Accounting Standard No. 141: Business Combinations, the Company’s allocation period will not exceed one year. The impact of any arbitration settlements described above will be reflected as a gain or loss in the statement of operations.

The Company engages in the business of acquiring and operating oil and natural gas interest. The Company owns interests in approximately 1,621 active oil producing and injection wells located in Indiana and Illinois.

Income Taxes

The Company has elected to be taxed under the provisions of Sub Chapter S of the Internal Revenue Code for federal and state tax purposes. Accordingly, income taxes are not reflected in the financial statements because the resulting profit and loss is included in the income tax returns of the individual stockholder.

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PENNTEX RESOURCES ILLINOIS, INC.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

Production Receivable

Production receivables correspond to approximately one month of oil revenue extracted and sold to buyers. The production receivable is valued at the invoiced amount and does not bear interest. The Company has assessed the financial strength of our customers and records bad debt as necessary.

Joint Interest Receivables

Joint interest receivables represent the Company’s billings to the non-operators associated with wells and are based on those owners’ working interests in the wells.

Inventory

Inventory consists of well tubing inventory and the Company’s ownership interests in oil held in terminal tanks located in the field. The tubing and oil inventory is valued at cost.

Financial Instruments

The Company’s financial instruments consist of cash, commodity collars, production receivables, accounts payable, and a line of credit facility.

Revenue Recognition

Oil revenue is recognized when the oil is delivered to or collected by the purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves our stock tanks and enters the purchaser’s trucks. It is the measurement of the purchaser that determines the amount of oil purchased (although there are provisions for challenging these measurements if we believe the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil purchases within 30 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil production is at our applicable field gathering system; therefore, we do not incur transportation costs related to our sales of oil production.

Hedging Activities

The Company mainly uses commodity collars, put options, and fixed price swaps to manage price risk in connection with the sale of oil and accounts for those contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The results of the Company’s oil hedging activities are reflected in the revenue section of the Statement of Operations.

The Company has established the fair value of all hedging instruments using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These

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PENNTEX RESOURCES ILLINOIS, INC.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. Values the Company reports in its financial statements change as the estimates are revised to reflect actual results, changes in market conditions, or other factors.

SFAS No. 133 establishes accounting and reporting standards requiring hedging activities be recorded at fair value and included in the Balance Sheet as assets or liabilities. The accounting for changes in fair value of a hedging instrument depends on the intended purpose of the hedge and the resulting designation, which is established at the inception of a hedge. For hedging instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in earnings. For hedging instruments designated as fair value hedges (in accordance with SFAS No. 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Hedge effectiveness is measured annually based on the relative changes in fair value between the hedging contract and the hedged item over time. However, the Company’s evaluations are not documented, and as a result, it is recording changes on the derivative valuations through earnings.

Overhead Reimbursement Fees

The Company has classified fees from overhead charges billed to working interest owners, including the Company, of $3,863,088 and $3,075,676 for the years ended December 31, 2006 and 2005, respectively, as a reduction of general and administrative expenses in the accompanying Statement of Operations. The Company’s share of these charges was $996,081 and $795,748 for the years ended December 31, 2006 and 2005, respectively, and is classified as operating expenses.

Reclassification

The prior year financial statements have been reclassified to conform to the current year presentation.

Oil Properties and Depreciation and Depletion

The Company accounts for its oil exploration and production activities under the successful efforts method of accounting.

Oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil properties. Oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of oil are capitalized. Workover costs are expensed as incurred.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of- production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved

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PENNTEX RESOURCES ILLINOIS, INC.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

Vehicles used in field operations are depreciated over a period of seven years.

The Company accounts for impairment under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future oil prices, operating costs, anticipated production from proved reserves, and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Management determined that no adjustments to the unamortized capitalized cost were necessary as of December 31, 2006 and 2005.

Upon the sale or retirement of proved oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

Accounting Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Accordingly, actual results could differ from those estimates. Among the more sensitive of the estimates involves determining the proved reserves, costs to plug a well, and salvage values of equipment, from which the asset retirement obligation and depletion expense is calculated. Estimates are utilized to determine the fair market value of the Company’s hedges. Also, management’s estimates and assumptions to determine future net cash flows that ascertain asset impairment, if applicable, are subject to variation from actual results.

Oil Reserve Quantities

The Company’s estimate of proved reserves is based on the quantities of oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. The Company’s independent engineering firm, Netherland, Sewell,

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and Associates, Inc., prepares a reserve and economic evaluation of all the Company’s properties on a lease-by-lease basis.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing its reserve reports. The accuracy of the Company’s reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil eventually recovered.

Asset Retirement Obligations

The Company applies SFAS No. 143, “Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS No. 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil properties, this is the period in which the oil well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of the Company’s oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the oil well is sold, at which time the liability is reversed. The asset retirement obligation is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0 percent.

A summary of the asset retirement obligation is as follows at December 31:

	2006			2005
Beginning Balance—Asset Retirement Obligation	$	854,041		$	924,000
Asset Retirement Obligation Adjustments		0			(147,599	)
Plugging Cost Incurred		(16,357	)		0
Additions to Asset Retirement Obligation		203			0
Current Year Accretion Expense		82,681			77,640
Total Asset Retirement Obligation	$	920,568		$	854,041

New Accounting Pronouncements

On March 30, 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the

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timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for the Company beginning January 1, 2005, and was applied in estimating the asset retirement obligation at December 31, 2005.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies that use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling, and (3) an aging of exploratory well costs suspended for greater than one year with the number of wells it is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Application of this pronouncement did not have a significant impact on the Company’s financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006.

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The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. The Company does not expect that adoption of this FASB Staff Position will have a material impact on its results of operations or financial position.

2. CONCENTRATIONS OF CREDIT RISK

At times during the year ended December 31, 2006, the Company’s cash balance may have exceeded the Federal Deposit Insurance Corporation’s insured limit of $100,000. There were no losses incurred due to concentrations.

By using derivative instruments to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative is positive, the counterparty owes the Company, which creates repayment risk. The Company minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.

3. HEDGING ACTIVITIES

The Company’s results of operations and operating cash flows are impacted by changes in market prices for oil. To mitigate a portion of the exposure to adverse market changes, the Company entered into oil hedges. As of December 31, 2006 and 2005, the Company’s oil hedging instruments consisted of collars and fixed price swaps. These instruments allow the Company to predict with greater certainty the effective oil price to be received for our hedged production.

Collars contain a fixed floor price (put) and ceiling price (call). The put options are purchased from the counterparty by the Company’s payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays the Company an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to

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the counterparty by the Company’s receipt of a cash premium. If the market price is greater than the call strike price for a calculation period, then the Company pays the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.

The Company sells oil in the normal course of its business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in oil sales. The Company enters into derivative instruments such as swap contracts to hedge a portion of its forecasted oil sales. Fixed price swaps with a liability of $427,020 were settled in January 2006. This obligation is included in accounts payable at December 31, 2005.

The Company incurred net payments of $2,110,677 and $4,599,517 under these hedges during years ended December 31, 2006 and 2005, respectively, which reduced operating revenue. Unrealized gains (losses) associated with these collars are included in operating revenue and amounted to $1,769,844 and ($2,480,740) for the years ended December 31, 2006 and 2005, respectively. Below is a summary of the Company’s asset/ (liability) hedging positions as of December 31, 2006:

Quantity	Notional Volume (Bls)	Period	Fixed Price		Floor/ Put Prices		Ceiling/ Call Prices		Fair Market Value
Collars	96,000	1/07–12/07	$	0	$	40.00	$	42.55	$	(2,098,391	)
Total Current Portion	96,000								$	(2,098,391	)
Collars	96,000	1/08–12/08	$	0	$	60.00	$	89.25	$	246,593
Collars	59,500	1/09–7/09	$	0	$	62.00	$	67.80		(122,944	)
Collars	40,000	8/09–12/09	$	0	$	62.00	$	66.10		(100,903	)
Total Long-Term Portion	195,500								$	22,746
Total Financial Instruments	291,500								$	(2,075,645	)

4. VEHICLE LOAN PAYABLE

The Company obtained a loan in 2005 in the amount of $367,267 to acquire approximately fifteen trucks used for field operations. The loan matures in June 2009 and incurs interest at 6.24 percent per annum. The table below outlines the future minimum payments due on the loan:

2007		90,330
2008		96,130
2009		52,792
2010		0
Total	$	239,252

5. LINE OF CREDIT FACILITY

On January 19, 2006, the Company and PennTex Resources, L.P., as co-borrowers, entered into a revolving line of credit of up to $22,500,000 with Manufacturers and Traders Trust Company, as agent (the “Agent”) (the “M&T Loan”). The Borrowing Base for the M&T line of credit was $18,500,000 as of December 31, 2006. Interest on the line of credit accrues and is payable at a rate per annum equal to the base rate from time to time in effect, plus one percent (1.0%). The base rate is equal to the rate of interest per annum then most recently established by the Agent as its “prime rate”, which rate may not be the lowest rate of interest charged by the

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Agent to its borrowers. Interest is calculated on unpaid sums actually advanced and outstanding and only for the period from the date or dates of such advances until repayment. There are no principal payments due monthly. The borrowers are jointly and severally liable with respect to borrowings under the M&T Loan. Each borrower has guaranteed the full and timely payment by the other borrower of each and every obligation and liability of such other borrower to the lenders. In addition, borrowings under the loan are guaranteed by the co-borrowers’ sole owner, Lance T. Shaner. The M&T line of credit is secured by each of the borrower’s assets and oil producing properties located in the states of Illinois and Indiana. The line of credit matures on January 16, 2009. The interest rate on the line of credit as of December 31, 2006 was 9.25 percent and the outstanding balance was $14,944,536, of which, $2,300,000 is allocated to the Company.

As of December 31, 2006, the Company and PennTex Resources, L.P., as co-borrowers, were not in compliance with the negative covenant in their credit agreement requiring that their ratio of current assets to current liabilities, as defined in the credit agreement, be at lease 1.1:1. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarters of 2007.

6. COMMITMENTS AND CONTINGENCIES

Due to the nature of the oil business, the Company is exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. The Company conducts periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort. Except as noted below, management knows of no significant probable or possible environmental contingent liabilities.

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company has not experienced any significant environmental liability, and, except as noted below, is not aware of any potential environmental issues or claims as of December 31, 2006.

At December 31, 2006, the Company’s Balance Sheet included reserves for the legal proceedings detailed below of $208,000. The accrual of reserves for legal matters is included in Accrued Expenses on the Balance Sheet. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional loss, the amount of which is not currently estimable, in excess of the amounts currently accrued with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in actual liability exceeding the estimated ranges of loss and the amounts accrued. Based on currently available information, the Company believes that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed current accruals by an amount that would have a material adverse effect on the consolidated financial position or results of operations of the Company, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

EPA Matter

In September 2006, the United States Department of Justice (“U.S. DOJ”) and the United States Environmental Protection Agency (“U.S. EPA”) initiated an enforcement action against the Company and Rex

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Energy Operating Corp. seeking mandatory injunctive relief and potential civil penalties based on allegations that the companies were violating the Clean Air Act in connection with the release of hydrogen sulfide (H2S) gas and other volatile organic compounds (“VOC’s”) in the course of the Company’s oil operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. The Company’s senior management and representatives of the U.S. EPA, U.S. DOJ, Illinois Environmental Protection Agency (“Illinois EPA”) and the Agency for Toxic Substances and Disease Registry (“ATSDR”) attended a meeting at the offices of the U.S. EPA in Chicago, Illinois on September 7, 2006, to discuss matters relating to the enforcement action. This meeting had been preceded by certain monitoring of air emissions in the areas surrounding Bridgeport, Illinois and Petrolia, Illinois that the U.S. EPA and ATSDR had conducted in May 2006.

As a result of the initial meeting with the government on September 7, 2006, and certain subsequent meetings and communications between the Company’s senior management and the U.S. EPA and U.S. DOJ, the Company and Rex Energy Operating Corp. executed a non-binding agreement in principle with the U.S. EPA effective October 24, 2006. In the agreement in principle, the Company and Rex Energy Operating Corp. agreed to develop and carry out a written response plan designed to further reduce possible emissions of H2S and VOC’s from the Company’s oil wells and facilities in the Lawrence Field that are closest to populated areas. The Company and Rex Energy Operating Corp. agreed to operate and maintain the control measures described in the response plan in accordance with a written operations and maintenance plan to be developed by the companies and approved by the U.S. EPA. The agreement in principle also required the companies to evaluate the effectiveness of the control measures in the Lawrence Field installed pursuant to the response plan through a monitoring program, and required the companies to evaluate the need for additional control measures at other facilities within the Lawrence Field within 60 days. The companies also agreed to present to the U.S. EPA any recommendations for further action the companies might develop based upon their observations of the effectiveness of the control measures. The Company, Rex Energy Operating Corp. and the U.S. EPA each agreed that they would use their best efforts to negotiate a proposed final settlement agreement that would resolve the government’s enforcement action, which settlement agreement would be published in the Federal Register and made subject to public comment prior to any final approval.

The senior management of the Company and Rex Energy Operating Corp. and the U.S. EPA and U.S. DOJ are negotiating the terms of a comprehensive consent decree in which the Company and Rex Energy Operating Corp., without any admission of wrongdoing or liability and without any agreement to pay any civil fine or penalty, would agree to install certain control measures and to implement certain operating and maintenance procedures regarding the Company’s oil operations in the Lawrence Field. Under the terms of the proposed consent decree, the companies would also agree to establish a monitoring protocol that would be designed to facilitate the reduction of possible emissions of H2S and VOC’s from the Company’s operations near Bridgeport, Illinois and Petrolia, Illinois. While at this time the Company is unable to predict with certainty the outcome of this enforcement action and the final terms and conditions of the consent decree, it believes that the Company will be able to reach a final settlement with the government agencies. The Company also believes that the consent decree will not require the Company or Rex Energy Operating Corp. to pay any civil fine or penalty, although it will provide for the possible imposition of specified daily fines and penalties for any days in which it might be determined that the companies have violated the terms and conditions of the consent decree. Any proposed consent decree will ultimately require the approval of a court of proper jurisdiction.

The Company intends to vigorously defend itself in this matter. In the event that the parties are unable to agree upon the final terms of the consent decree or if the consent decree is not ultimately approved by a court of proper jurisdiction, the Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable.

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Leib Case

The Company and Rex Energy Operating Corp. are defendants in a putative class action lawsuit that has been filed in the United States District Court for the Southern District of Illinois, Cause Number 3:06-CV-00802-JPG-CJP, styled “Julia Leib, et al. v. Rex Energy Operating Corp., et al.” This action was commenced on October 17, 2006, by plaintiffs, Julia Leib and Lisa Thompson, individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport, Illinois and Petrolia, Illinois. The complaint asserts that the operation of oil wells that are controlled, owned or operated by the Company and Rex Energy Operating Corp. has resulted in “serious contamination” of the class area with H2S. The complaint asserts several causes of action, including violation of the Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct. The complaint seeks, among other things, injunctive relief under the Illinois Environmental Protection Act and Illinois common law, compensatory and other damages, punitive damages, and attorneys’ fees and costs. In addition, the complaint seeks the creation of a court-supervised, defendant-financed fund to pay for medical monitoring for the plaintiffs and others in the class area.

On November 14, 2006, the Company and Rex Energy Operating Corp. filed a joint answer to the complaint specifically denying virtually all of the allegations in the complaint and asserting affirmative defenses thereto. On December 20, 2006, the plaintiffs filed a motion for class certification requesting that the court certify the case as a class action. The Company intends to vigorously oppose the plaintiffs’ motion for certification of the case as a class action.

Pursuant to the terms of a pollution liability policy with Federal Insurance Company, the Company has insurance coverage for possible damages relating to claims made in this lawsuit for up to $1,000,000. In addition, in accordance with the terms of the pollution liability policy, Federal Insurance Company has agreed to conduct the Company’s defense in this lawsuit at the insurer’s expense. Under the terms of a written agreement with the Company, Federal Insurance Company has agreed to pay a substantial portion of the Company’s costs and expenses relating to the defense of this lawsuit, including attorneys’ fees. Under the terms of the agreement, the Company is required to pay the costs and expenses relating to the defense in excess of the amounts payable by Federal Insurance Company.

The Company intends to vigorously defend against the claims that have been asserted against it in this lawsuit. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or the range of potential loss should the outcome be unfavorable.

7. RELATED PARTY TRANSACTIONS

The Company’s sole stockholder, Lance T. Shaner, owns a controlling interest in PennTex Resources, L.P., a Delaware limited partnership (“PennTex L.P.”) and Rex Energy IV, LLC, a Delaware limited liability company (“Rex IV”). PennTex L.P. owns a 25.0 percent working interest and Rex IV owns a 49.0 percent working interest in the oil producing properties operated by the Company. As operator, the Company charged $957,770 and $817,239 of overhead charges to PennTex L.P. for the years ended December 31, 2006 and 2005, respectively. The Company charged $480,575 of overhead charges to Rex IV for its initial period October 1, 2006 to December 31, 2006. As disclosed in the Summary of Significant Accounting Policies, total charges for overhead billed to working interest owners of $3,863,088 and $3,075,676 for the years ended December 31, 2006 and 2005, respectively, is classified as a reduction of general and administrative expenses.

The Company incurred $2,609,774 and $1,849,820 in overhead fees to Rex Energy Operating Corp., a Delaware corporation and a related party, for the years ended December 31, 2006 and 2005, respectively. Rex

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Energy Operating Corp. also incurs well operating expenses on behalf of the Company and passes along these costs to the Company. Such expenses, included in operating expense, were $3,071,570 and $3,194,107 for the years ended December 31, 2006 and 2005, respectively.

During 2005, the Company obtained two working capital loans from two related parties for a total of $1,400,000. The loans incurred interest at a rate of 13.0 percent per annum. The total interest expense associated with the loans was $118,118. There was no outstanding balance on either loan at December 31, 2005.

At December 31, 2005, there was a receivable due from Lance T. Shaner in the amount of $700,000 with no term or due date. This amount was repaid in January 2006.

At December 31, 2006, there was a working capital loan payable to Lance T. Shaner in the amount of $1,820,000 with no term or due date.

The Company had a related party receivable due from affiliates recorded for $1,580,098 at December 31, 2006. This amount related primarily to the payment of invoices on behalf of PennTex Resources, L.P. where settlement occurs monthly. At December 31, 2005, there were no related party receivables and $317,894 of related party payables owed to affiliates.

8. MAJOR CUSTOMER

The Company sold 100.0 percent of its oil production in the Indiana and Illinois fields to Countrymark Cooperative, LLP in 2005 and 2006.

9. FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments.

The fair value of the liability associated with the Company’s hedging instruments is $2,075,645 and $3,845,489 at December 31, 2006 and 2005, respectively. The fair value is based on valuation methodologies of the Company’s counterparty. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

10. LITIGATION

ERG v. Tsar Energy II, LLC

At December 31, 2005, the Company was involved in a lawsuit with Tsar Energy II, LLC (“Tsar”) and Richard A. Cheatham in the 334th Judicial District Court of Harris County, Texas, cause number 2004-39584, and styled “ERG Illinois, Inc. And Scott Y. Wood v. Tsar Energy II, LLC and Richard M. Cheatham.” The dispute centered around overhead fees charged by the Company as operator of jointly-owned oil producing

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properties located in Illinois and Indiana in which the Company owns a 26.0 percent working interest. Tsar then owned a 49.0 percent non-operator working interest in the subject properties. The Company (then known as ERG Illinois, Inc.) and its former owner, Scott Y. Wood (“Wood”), commenced this litigation in July 2004, by filing a petition against Tsar and its president, Richard M. Cheatham, seeking, among other things, a declaratory judgment that the Company, as the operator of the subject properties, was entitled to charge Tsar and the other non-operators their proportionate shares of a fixed monthly overhead charge of $300 for each producing well located within the North Lawrence Unit portion of the properties pursuant to the terms of a operating agreement relating to such unit.

Tsar filed counterclaims against the Company (the known as ERG Illinois, Inc.) asserting (i) a breach of contract and declaratory judgment claim seeking an unspecified amount of actual damages along with declaratory relief based on allegations that the Company breached both the joint operating agreement covering the properties in question and a March 2004 letter of intent that preceded it by charging Tsar its proportionate share of a fixed monthly overhead charge of $300 for each producing well located in the North Lawrence Unit portion of the subject properties, (ii) breach of contract claim against the Company seeking $100,000 in actual damages based on Tsar’s allegation that the Company breached a verbal agreement between the parties relating to an extension fee, (iii) a claim seeking an unspecified amount of actual and punitive damages based on Tsar’s assertion that the Company committed fraud in the inducement in connection with Tsar’s acquisition on March 16, 2004 of its 49.0 percent non-operating working interest in the subject properties by allegedly making false representations prior to and in the letter of intent executed by the Company and Tsar and (iv) a conversion claim seeking actual damages of $100,000 plus an unspecified amount of punitive damages based on Tsar’s allegations that the Company improperly converted funds belonging to Tsar.

On December 22, 2005, the Company filed motions for summary judgment regarding the principal contract claims at issue and the tort counterclaims that had been asserted against it by Tsar. By order signed February 8, 2006, the court granted the Company’s motion for summary judgment sustaining its right to charge the non-operators of the subject properties their proportionate shares of a fixed monthly overhead charge of $300 for each producing well located within the North Lawrence Unit. By the same order, the court denied the Company’s motions for summary judgment seeking dismissal of Tsar’s fraud in the inducement and conversion counterclaims. On March 3, 2006, the Company and Tsar jointly moved to sever into a separate action, the claims and counterclaims relating to the Company’s charging of fixed monthly overhead on producing wells in the North Lawrence Unit so that the court would be able to sign a final, appealable judgment in the Company’s favor on the issues resolved by the court’s summary judgment ruling. The court granted this joint motion on March 3, 2006 and the severed action was docketed in the district court as a severed case styled “ERG Illinois, Inc. v. Tsar Energy II, LLC and Richard M. Cheatham,” bearing cause number 2004-39584-A. On March 31, 2006, Tsar appealed the district court’s final judgment in the severed action to the Court of Appeals First District of Texas.

On October 3, 2006, Rex Energy IV, LLC, a Delaware limited liability company affiliated with the Company, acquired the 49.0 percent working interest of Tsar in the Illinois and Indiana properties at issue in the above cases. As part of this transaction, and without payment of any separate consideration, the Company obtained a written settlement agreement requiring Tsar and its principal, Richard M. Cheatham, to dismiss with prejudice the claims that they had asserted against the Company in both the severed and non-severed actions, and to deliver a mutual release releasing the Company and certain other affiliates of the Company from any and all liability for claims that had been asserted (or could have been asserted) in the two cases by Tsar and Cheatham. Pursuant to this settlement agreement, the claims asserted against the Company in the non-severed action pending in the 334th Judicial District Court of Harris County, Texas, were dismissed with prejudice by an order

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NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

signed on October 5, 2006. The claims asserted against the Company in the severed action were dismissed with prejudice by the Court of Appeals First District of Texas by judgment rendered on October 26, 2006, thereby bringing to a final conclusion not only the appellate case, but the underlying severed district court case from which the appeal had been brought.

Audit Exceptions Claim

On February 1, 2006, the Company was served with a draft audit report prepared by an outside auditor retained by Tsar to audit the joint interest billings that were made by the Company. The time period of the audit report was March 1, 2004 through June 30, 2005. The audit report purported to identify potential audit exception claims totaling $17,269,956, plus additional unspecified amounts to be determined. However, the audit report identified only $334,180 of audit exception claims that were alleged to be owed to Tsar, and of this amount, $100,000 was attributable to an extension fee dispute which was the subject of two of Tsar ‘s counterclaims in the ERG vs. Tsar litigation discussed above. In addition, $2,510,853 of the gross amount of the audit exceptions claims described in the audit report was attributable to the fixed monthly overhead charges of $300 per producing well in the North Lawrence Unit portion of the jointly owned properties that was upheld as a matter of law by the court’s summary judgment ruling rendered February 8, 2006 in the ERG vs. Tsar litigation described above.

On February 3, 2006, Tsar filed a formal nonsuit without prejudice to its breach of contract counterclaim asserted against the Company in the ERG vs. Tsar case that had sought to recover damages if an accounting of the charges to the joint account revealed that they were inaccurate. On July 31, 2006, the Company submitted to Tsar its written response to Tsar’s audit report. The Company’s response stated that the majority of the audit exceptions set forth in the audit report were unsupported, not evidenced by true audit work, based on supposition and hearsay, and not presented in the manner required by applicable guidance of the Council of Petroleum Accounting Societies (“COPAS”). The majority of the audit exceptions set forth in the report were denied by the Company; however, the Company identified costs and expenses totaling $106,616 which were owed to the Company by Tsar.

In connection with the settlement of the Tsar lawsuit (See ERG v. Tsar Energy II, LLC above), the Company, without payment of any separate consideration, obtained a full and complete release of the audit exception claims asserted by Tsar in its audit report dated February 1, 2006. This release, which was executed by Tsar on October 3, 2006, was obtained pursuant to the acquisition transaction pursuant to which Rex Energy IV, LLC, a company affiliated with the Company, acquired the working interest of Tsar in the jointly-owned oil producing properties located in Illinois and Indiana.

11. COSTS INCURRED IN OIL ACQUISITION AND DEVELOPMENT ACTIVITIES

Costs incurred by the Company in oil property acquisitions and developments are presented below and include the acquisition as described in Note 1:

	2006		2005
Oil Property Acquisition Costs	$	203	$	7,657,449
Development Costs		1,392,409		420,657
Total	$	1,392,612	$	8,078,106

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather oil.

F-355

PENNTEX RESOURCES ILLINOIS, INC.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

12. OIL PROPERTY CAPITALIZED COSTS

Aggregate capitalized costs for the Company related to oil production activities with applicable accumulated depreciation and depletion are presented below:

	2006			2005
Proved Oil Properties	$	8,614,317		$	7,301,705
Total		8,614,317			7,301,705
Less: Accumulated Depreciation and Depletion		(1,482,905	)		(587,110	)
Total	$	7,131,412		$	6,714,595

13. RESULTS OF OIL PRODUCING ACTIVITIES

The results of operations for oil producing activities (excluding overhead and interest costs) are presented below:

	2006			2005
Revenue
Oil Sales	$	10,011,844		$	9,102,896
Realized Losses on Hedges		(2,110,677	)		(4,599,517	)
Unrealized Gain (Loss) on Hedges		1,769,844			(2,480,740	)
Net Oil Sales		9,671,011			2,022,639
Expenses
Operating Expenses		5,211,366			5,023,152
Production Taxes		34,562			78,301
Accretion Expense on Asset Retirement Obligation		82,681			77,640
Depreciation and Depletion		1,010,049			587,110
Total Expenses		6,338,658			5,766,203
Results of Operations for Oil Producing Activities	$	3,332,353		$	(3,743,564	)

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, and other production taxes. In addition, production costs include administrative expenses applicable to support equipment associated with these activities.

Depreciation and depletion expense includes those costs associated with capitalization acquisitions and development costs, but does not include the depreciation applicable to support equipment.

There is no provision for income taxes because the Company is a nontaxable entity.

14. OIL RESERVE QUANTITIES (UNAUDITED)

The Company’s independent engineers, Netherland, Sewell and Associates, Inc., have evaluated the Company’s proved reserves associated with oil properties located in Indiana and Illinois.

F-356

PENNTEX RESOURCES ILLINOIS, INC.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

The Company emphasizes that reserve estimates are inherently imprecise. Its oil reserve estimates of properties located in Indiana and Illinois were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

Proved oil reserves represent the estimated quantities of oil which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by oil and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

Presented below is a summary of changes in estimated reserves of the oil wells located in Illinois and Indiana at December 31, 2006:

	Oil (bls)
Proved Reserves—Beginning of Period	2,399,723
Plus/Minus Revisions of Previous Estimates	(223,962	)
Production	(161,934	)
Proved Reserves—End of Period	2,013,827
Proved developed reserves
December 31, 2005	2,180,030
December 31, 2006	1,645,932

15. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

Statement of Financial Accounting Standard No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proven reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0 percent annual discount factor.

F-357

PENNTEX RESOURCES ILLINOIS, INC.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth the Company’s future net cash flows relating to proved oil reserves based on the standardized measure prescribed by SFAS 69 at December 31, 2006:

Future Cash Inflows	(a)$	114,204,129
Future Production Costs		(69,980,157	)
Future Abandonment Costs		(2,088,033	)
Future Development Costs		(3,771,450	)
Net Future Cash Inflows		38,364,489
Less: Effect of a 10.0% Discount Factor		(13,879,203	)
Standardized Measure of Discounted Future Cash Flows	$	24,485,286

(a) Calculated using weighted average prices of $56.71 per barrel of oil.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

Standardized Measure—Beginning of Period	$	34,311,219
Sales of Oil Produced—Net of Production Costs		(4,765,884	)
Net Changes in Prices and Production Costs		(6,399,264	)
Changes in Future Development Costs		(617,671	)
Changes in Timing and Other		1,211,126
Future Abandonment Costs		(920,568	)
Development Costs Incurred		1,324,065
Revisions of Previous Quantity Estimates		(3,088,859	)
Accretion of Discount		3,431,122
Standardized Measure—End of Period	$	24,485,286

16. RESTATEMENT OF PREVIOUSLY ISSUED STATEMENTS DUE TO CORRECTIONS

The Company has restated its previously issued 2005 financial statements for matters related to the previously unreported item of recognition of well tubing inventory costs. The capitalization of these costs makes the financial statements presented in this report comparable. The accompanying financial statements for 2005 have been restated to reflect the corrections. The following is a summary of the restatements for 2005:

Capitalize 2005 Well Tubing Inventory	$	291,240
Total Increase in 2005 Earnings	$	291,240

F-358

PENNTEX RESOURCES ILLINOIS, INC.

NOTES TO FINANCIAL STATEMENTS—(Continued)

YEARS ENDED DECEMBER 31, 2006 AND 2005

The effect on the Company’s previously issued 2005 financial statements are summarized as follows:

Balance Sheet as of December 31, 2005

	Previously Reported			Increase (Decrease)		Restated
Oil and Tubing Inventory	$	96,281		$	291,240	$	387,521
Current Assets	$	2,017,475		$	291,240	$	2,308,715
Total Assets	$	9,246,089		$	291,240	$	9,537,329
Total Stockholders’ Deficit	$	(2,483,183	)	$	291,240	$	(2,191,943	)
Total Liabilities and Stockholders’ Deficit	$	9,246,089		$	291,240	$	9,537,329

Statement of Operations for the Year Ended December 31, 2005

	Previously Reported			Increase (Decrease)			Restated
Operating Expenses	$	5,314,392		$	(291,240	)	$	5,023,152
Net Loss	$	(4,587,201	)	$	291,240		$	(4,295,961	)

17. SUBSEQUENT EVENTS

On January 26, 2007, the United States District Court for the Southern District of Illinois, in the case of the putative class action lawsuit filed against the Company and Rex Energy Operating Corp. (See Note 6), issued a scheduling and discovery order establishing deadlines for completing discovery and briefing relating to the plaintiffs’ motion for class certification. The order states that after the filing of the last brief on class certification issues on August 31, 2007, the court will schedule a hearing on plaintiffs’ motion for class certification. The Company intends to vigorously oppose the plaintiffs’ motion for certification of the case as a class action. On January 31, 2007, the plaintiffs in the above action filed a motion for leave seeking permission to file an amended complaint that would add a claim against the defendants for alleged violation of Section 7002(a)(1) of the Resource Conservation And Recovery Act (“RCRA”). Plaintiffs’ proposed amended complaint makes factual allegations similar to those previously asserted in Plaintiffs’ prior pleadings. The Company believes that it is likely that the court will grant Plaintiffs’ leave to file the amended complaint. On February 6, 2007, the court set a final pretrial conference for this case for August 7, 2008. The case is scheduled for jury trial on August 18, 2008, in the United States District Court for the Southern District of Illinois located in Benton, Illinois. The parties to this lawsuit have exchanged initial pretrial disclosures as required under the applicable rules and each side has served and responded to pre-deposition written discovery. The Company intends to vigorously defend against the claims that have been asserted against it in this lawsuit. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or the range of potential loss should the outcome be unfavorable to it.

As of December 31, 2006, the Company and PennTex Resources, L.P., as co-borrowers, were not in compliance with the negative covenant in their credit agreement requiring that their ratio of current assets to current liabilities, as defined in the credit agreement, be at lease 1.1:1. The companies have received a waiver of this covenant for the fourth quarter of 2006 and the first and second quarters of 2007.

F-359

Oil Property acquired from ERG Illinois, Inc.

F-360

INDEPENDENT AUDITORS’ REPORT

To the Shareholder of

PennTex Resources Illinois, Inc.

State College, PA

We have audited the accompanying statement of revenues and direct operating expenses of the oil property acquired from ERG Illinois, Inc. for the period March 1, 2004 through December 31, 2004. This financial statement is the responsibility of PennTex Resources Illinois, Inc.’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of revenue and direct operating expenses is free of material misstatement. An audit of a statement of revenues and direct operating expenses includes examining, on a test basis, evidence supporting the amounts and disclosures in that financial statement. An audit of a statement of revenues and direct operating expenses also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit of the statement of revenues and direct operating expenses provides a reasonable basis for our opinion.

The accompanying statement of revenues and direct operating expenses was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and exclude material expenses, as described in Note 1 to the financial statement, that would not be comparable to those resulting from the proposed future operations of the oil property and is not intended to be a complete presentation of revenues and expenses.

In our opinion, the statement of revenues and direct operating expenses referred to above presents fairly, in all material respects the revenues and direct operating expenses of the oil property acquired from ERG Illinois, Inc. as described in Note 1 for the period March 1, 2004 through December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

Malin, Bergquist & Company, LLP

Pittsburgh, PA

April 19, 2007

F-361

PENNTEX RESOURCES ILLINOIS, INC.

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES—

OIL PROPERTY ACQUIRED FROM ERG ILLINOIS, INC.

FOR THE PERIOD MARCH 1, 2004 THROUGH DECEMBER 31, 2004

	2004
Revenues—oil sales	$	6,142,557
Direct operating expenses		4,159,290
Excess of revenues over direct operating expenses	$	1,983,267

SEE ACCOMPANYING NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES.

F-362

PENNTEX RESOURCES ILLINOIS, INC.

(OIL PROPERTY ACQUIRED FROM ERG ILLINOIS, INC.)

NOTES TO FINANCIAL STATEMENT

FOR THE PERIOD MARCH 1, 2004 THROUGH DECEMBER 31, 2004

Note 1. BASIS OF PRESENTATION

The accompanying financial statement presents the revenues and direct operating expenses of the oil property (the Property) acquired from ERG Illinois, Inc. (ERG) for the period March 1, 2004 through December 31, 2004. Lance T. Shaner acquired 100.0 percent of the common stock of ERG effective January 1, 2005 for approximately $5.96 million. ERG was the operator of the Property located in the states of Illinois and Indiana and has a corresponding 26.0 percent working interest in the Property. Following the acquisition of common stock, ERG was renamed to PennTex Resources Illinois, Inc. (the Company). The transaction was accounted for as a purchase, and the excess of the purchase price over the ERG equity was pushed down to the Balance Sheet of the Company.

The accompanying statement of revenues and direct operating expenses of the Property does not include general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes since historical expenses of this nature incurred by ERG are not necessarily indicative of the costs to be incurred by the Company.

Revenues in the accompanying statement of revenues and direct operating expenses are recognized on the entitlement method. Direct operating expenses are recognized on the accrual basis and consist of monthly operator overhead costs and other direct costs of operating the Property which were charged to the joint account of working interest owners by the operator of the wells. Direct operating expenses include all costs associated with production, marketing and distribution, including all selling and direct overhead other than costs of general corporate activities.

Historical financial information reflecting financial position, results of operations, and cash flows of the Property is not presented because the purchase price was assigned to the oil property interests and related equipment acquired. Other assets acquired and liabilities assumed were not material. In addition, the Property was a part of a larger enterprise prior to the acquisition by the Company, and representative amounts of general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the Property acquired, nor would such allocated historical costs be relevant to future operations of the Property. Development and exploration expenditures related to the Property were insignificant in the relevant periods. Accordingly, the historical statement of revenues and direct operating expenses of ERG’s interest in the Property is presented in lieu of the financial statements required under Item 3-05 of Securities and Exchange Commission Regulation S-X.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Note 2. SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL PRODUCING ACTIVITIES (UNAUDITED)

The following reserve estimates present the Company’s estimate of the proven oil reserves and net cash flow of the Property which is a United States property.

The Company emphasizes that reserve estimates are inherently imprecise. Our oil reserve estimates of wells located in Indiana and Illinois were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

F-363

PENNTEX RESOURCES ILLINOIS, INC.

(OIL PROPERTY ACQUIRED FROM ERG ILLINOIS, INC.)

NOTES TO FINANCIAL STATEMENT—(Continued)

FOR THE PERIOD MARCH 1, 2004 THROUGH DECEMBER 31, 2004

Proved oil reserves represent the estimated quantities of oil which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by oil and natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

(a) Reserve Quantity Information

Presented below is a summary of changes in estimated reserves of the oil wells at December 31, 2004. The reserves are proved.

	December 31 2004
	Oil(bls)
Proved Reserves—Beginning of Period	1,213,624
Plus/(Minus) Revisions of Previous Estimates	(106,436	)
Production	(168,798	)
Proved Reserves—End of Period	938,390

(b) Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves

The standardized measure of discounted future net cash flows relating to proved oil reserves (Standardized Measure) is a disclosure requirement under Statement of Financial Accounting Standard No. 69.

The Standardized Measure does not purport to be, nor should it be interpreted to present, the fair value of the oil reserves of the Property. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs are based on period-end sales prices for oil, estimated future production of proved reserves and estimated future production and development costs of proved reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

F-364

PENNTEX RESOURCES ILLINOIS, INC.

(OIL PROPERTY ACQUIRED FROM ERG ILLINOIS, INC.)

NOTES TO FINANCIAL STATEMENT—(Continued)

FOR THE PERIOD MARCH 1, 2004 THROUGH DECEMBER 31, 2004

The standardized measure of discounted future net cash flows relating to proved oil reserves is as follows at December 31, 2004:

	2004
Future Cash Inflows	(a) $	26,744,152
Future Production Costs		(23,148,335	)
Future Development Costs		0
Net Future Cash Inflows		3,595,817
Less: Effect of 10% Discount Factor		(667,086	)
Standardized Measure of Discounted Future Net Cash Flow	$	2,928,731

(a) Calculated using weighted average prices of $28.50 per barrel of oil.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

	2004
Standardized Measure—Beginning of Period	$	5,371,137
Sales of Oil Produced—net of production costs		(1,983,267	)
Net Changes in Prices and Production costs		(1,543,291	)
Revisions in previous quantity estimate		(332,188	)
Accretion of Discount		537,114
Changes in timing and other		879,226
Standardized Measure—End of Period	$	2,928,731

Estimates of economically recoverable oil reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geological formations and other matters. Actual quantities of oil may differ materially from the amounts estimated.

F-365

Rex Energy IV LLC

F-366

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of

Rex IV, LLC

State College, Pennsylvania

We have audited the balance sheet Rex IV, LLC as of December 31, 2006 and the related statements of operations, changes in members’ equity and cash flows for the period from inception to December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rex IV, LLC as of December 31, 2006, and the results of its operations and its cash flows for the period from inception to December 31, 2006 in conformity with accounting principles generally accepted the United States of America.

Pittsburgh, Pennsylvania

March 15, 2007

F-367

REX ENERGY IV, LLC

BALANCE SHEET

DECEMBER 31, 2006

ASSETS
CURRENT ASSETS
Cash	$	239,683
Production Receivable		1,348,090
Related Party Receivable		47,039
Other Receivables		226,897
Financial Instruments—Current Portion		15,633
Oil Inventory		174,887
TOTAL CURRENT ASSETS		2,052,229
PROPERTY AND EQUIPMENT
Proved Oil Properties		37,430,910
Less: Accumulated Depreciation and Depletion		(1,064,648	)
NET PROPERTY AND EQUIPMENT		36,366,262
LOAN COST—Net of Accumulated Amortization of $326,413		326,413
TOTAL ASSETS	$	38,744,904
LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Revolving Line of Credit Facility	$	37,580,634
Related Party Payable		8,877
Accrued Expenses		854,115
TOTAL CURRENT LIABILITIES		38,443,626
OTHER LIABILITIES
Asset Retirement Obligation		1,619,576
Financial Instruments Payable—Long-Term Portion		1,220,900
TOTAL OTHER LIABILITIES		2,840,476
TOTAL LIABILITIES		41,284,102
COMMITMENTS AND CONTINGENCIES (Note 5)
TOTAL MEMBERS’ DEFICIT		(2,539,198	)
TOTAL LIABILITIES AND MEMBERS’ DEFICIT	$	38,744,904

SEE ACCOMPANYING NOTES.

F-368

REX ENERGY IV, LLC

STATEMENT OF OPERATIONS

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

OPERATING REVENUE
Oil Sales	$	3,993,490
Realized Gain on Hedges		91,335
Unrealized Loss on Hedges		(1,205,267	)
TOTAL OPERATING REVENUE		2,879,558
OPERATING EXPENSES
Operating Expenses		2,393,285
Production Taxes		28,246
General and Administrative		661,263
Accretion Expense on Asset Retirement Obligation		143,882
Depreciation, Depletion and Amortization		1,391,061
TOTAL OPERATING EXPENSES		4,617,737
LOSS FROM OPERATIONS		(1,738,179	)
OTHER INCOME (EXPENSE)
Interest Expense		(801,119	)
TOTAL OTHER EXPENSE		(801,119	)
NET LOSS	$	(2,539,298	)

SEE ACCOMPANYING NOTES.

F-369

REX ENERGY IV, LLC

STATEMENT OF CHANGES IN MEMBERS’ EQUITY (DEFICIT)

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

	Total Members’ Equity (Deficit)
BALANCE—January 1, 2005	$	0
CAPITAL CONTRIBUTION		100
NET LOSS		(2,539,298	)
BALANCE—December 31, 2005	$	(2,539,198	)

SEE ACCOMPANYING NOTES.

F-370

REX ENERGY IV, LLC

STATEMENT OF CASH FLOWS

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(2,539,298	)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization		1,391,061
Accretion Expense		143,882
Unrealized Loss on Hedges		1,205,267
(Increase) Decrease in
Production Receivables		(1,348,090	)
Inventory		(62,454	)
Other Receivables		(226,797	)
Related Party Receivable		(47,039	)
Increase (Decrease) in
Current Year Plugging Costs Incurred		(9,428	)
Related Party Payable		8,877
Accrued Expenses		741,682
NET CASH PROVIDED USED BY OPERATING ACTIVITIES		(742,337	)
CASH FLOWS USED BY INVESTING ACTIVITIES
Acquisition of Oil Properties and Related Equipment		(35,110,357	)
Development of Oil Properties and Related Equipment		(835,431	)
NET CASH USED BY INVESTING ACTIVITIES		(35,945,788	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Revolving Credit Line		37,580,634
Loan Costs		(652,826	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		36,927,808
NET INCREASE IN CASH		239,683
CASH—BEGINNING		0
CASH—ENDING	$	239,683
SUPPLEMENTAL DISCLOSURES
Interest Paid	$	631,695
Non-Cash Transactions
Loan Costs Paid by Line of Credit Draws	$	505,516
Capital Contributions Included in Other Accounts Receivable	$	100

SEE ACCOMPANYING NOTES.

F-371

REX ENERGY IV, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Description of Business

Rex Energy IV, LLC (“the Company”) was organized in accordance with the Delaware Limited Liability Company Act on September 13, 2006. The voting members of the Company are Lance T. Shaner (50.0 percent voting interest and 50.0 percent economic interest) and Benjamin W. Hulburt (25.0 percent voting interest and 15.0 percent economic interest), and Thomas F. Shields (25.0 percent voting interest and 7.0 percent economic interest). There are also four non-voting members each with a 0.0 percent voting interest and 7.0 percent economic interest in the Company. The Company engages in the acquisition of ownership interests in oil and natural gas reserves located on proved developed properties. The Company is managed by a board of managers comprised of voting members the Company. The current board members are Lance T. Shaner, Benjamin W. Hulburt, and Thomas F. Shields. Board members vote in accordance with their voting interest on matters before the board. In the event of a tie in voting of board members, Lance T. Shaner, as Chairman of the Board, casts the deciding vote.

On October 3, 2006, the Company acquired average working interests of 49.0 percent in certain oil producing properties and related wells and equipment located in the Lawrence, West Kenner, and St. James fields in Illinois, and the El Nora field in Indiana (the “Illinois and Indiana Properties”) for $35,171,970 from TSAR Energy II, L.L.C., a Texas limited liability company (“Tsar”). The effective date of the acquisition was October 1, 2006. PennTex Resources, L.P. (“PennTex LP’) and PennTex Resources Illinois, Inc. (“PennTex Illinois”), companies affiliated with the Company, own average working interests of 25.0 percent and 26.0 percent, respectively, in the Illinois and Indiana Properties. PennTex Illinois is the operator of the Illinois and Indiana Properties. As part of this transaction, and without payment of any separate consideration, PennTex Illinois obtained a written settlement agreement requiring Tsar and its principal, Richard M. Cheatham, to dismiss with prejudice the claims that they had asserted against PennTex Illinois in two cases filed in 334th Judicial District Court of Harris County, Texas, the first being cause number 2004-39584, and styled “ERG Illinois, Inc. And Scott Y. Wood v. Tsar Energy II, LLC And Richard M. Cheatham.” and the second case being a severed action styled “ERG Illinois, Inc. v. Tsar Energy II, LLC And Richard M. Cheatham,” bearing cause number 2004-39584-A. The dispute in these cases centered around overhead fees charged by PennTex Illinois (at the time of the filing, then known as ERG Illinois, Inc.) as operator of Illinois and Indiana Properties. The settlement agreement also required Tsar and Mr. Cheatham to deliver a mutual release releasing PennTex Illinois and certain other affiliates of that company from any and all liability for claims that had been asserted (or could have been asserted) in the case by Tsar and Cheatham. The acquisition of the working interest of Tsar in the Illinois and Indiana Properties by the Company was accounted for as a purchase.

The Company allocated the purchase price as follows:

Interest in Oil Producing Properties	$	36,595,479
Oil Inventory		112,433
Asset Retirement Obligation		(1,485,122	)
Accrued Real Estate Taxes		(50,820	)
Total	$	35,171,970

Income Taxes

The Company elected to be treated as a partnership for federal and state tax purposes. Accordingly, income taxes are not reflected in the financial statements because the resulting profit and loss is included in the income tax returns of the individual members.

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FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

Production Receivable

Production receivables correspond to approximately one month of oil revenue extracted and sold to buyers. The production receivable is valued at the invoiced amount and does not bear interest. The Company has assessed the financial strength of its customers and records bad debt as necessary.

Inventory

Inventory consists of the Company’s ownership interests in oil held in terminal tanks located in the field. The inventory is valued at cost.

Financial Instruments

The Company’s financial instruments consist of cash, commodity collars, production receivables, accounts payable, and a line of credit facility.

Revenue Recognition

Oil revenue is recognized when the oil is delivered to or collected by the purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves our stock tanks and enters the purchaser’s trucks. It is the measurement of the purchaser that determines the amount of oil purchased (although there are provisions for challenging these measurements if we believe the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil purchases within 30 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil production is at our applicable field gathering system; therefore, we do not incur transportation costs related to our sales of oil production.

Hedging Activities

The Company mainly uses fixed price swaps to manage price risk in connection with the sale of oil and accounts for those contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The results of the Company’s oil hedging activities are reflected in the revenue section of the Statement of Operations.

The Company has established the fair value of all hedging instruments using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. Values the Company reports in its financial statements change as the estimates are revised to reflect actual results, changes in market conditions, or other factors.

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FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

SFAS No. 133 establishes accounting and reporting standards requiring hedging activities be recorded at fair value and included in the Balance Sheet as assets or liabilities. The accounting for changes in fair value of a hedging instrument depends on the intended purpose of the hedge and the resulting designation, which is established at the inception of a hedge. For hedging instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in earnings. For hedging instruments designated as fair value hedges (in accordance with SFAS No. 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Hedge effectiveness is measured annually based on the relative changes in fair value between the hedging contract and the hedged item over time. However, the Company’s evaluations are not documented, and as a result, it is recording changes on the derivative valuations through earnings.

Loan Costs

Loan costs consist of debt issuance costs and legal fees associated with establishing the revolving line of credit facility that are amortized over the term of the related debt. The gross carrying value of the loan fees is $652,826 and is presented net of the accumulated amortization of $326,413 for the initial period ended December 31, 2006.

Oil Properties and Depreciation and Depletion

The Company accounts for its oil exploration and production activities under the successful efforts method of accounting.

Oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil properties. Oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of oil are capitalized. Workover costs are expensed as incurred.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful

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FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

lives of 3 to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

The Company accounts for impairment under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future oil prices, operating costs, anticipated production from proved reserves, and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Management determined that no adjustments to the unamortized capitalized cost were necessary as of December 31, 2006.

Upon the sale or retirement of proved oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

Accounting Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Accordingly, actual results could differ from those estimates. Among the more sensitive of the estimates involves determining the proved reserves, costs to plug a well, and salvage values of equipment, from which the asset retirement obligation and depletion expense is calculated. Estimates are utilized to determine the fair market value of the Company’s hedges and plugging liabilities. Also, management’s estimates and assumptions to determine future net cash flows that ascertain asset impairment, if applicable, are subject to variation from actual results.

Oil Reserve Quantities

The Company’s estimate of proved reserves is based on the quantities of oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell, and Associates, Inc. prepares a reserve and economic evaluation of all the Company’s properties on a lease-by-lease basis.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of the Company’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil eventually recovered.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

Asset Retirement Obligations

The Company adopted and applied SFAS No. 143, “Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS No. 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which the oil and natural gas well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of the Company’s oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is reversed. The asset retirement obligation is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0 percent.

A summary of the asset retirement obligation is as follows at December 31:

	2006
Beginning Balance—Asset Retirement Obligation	$	0
Initial Asset Retirement Obligation Recorded for Acquisition		1,485,122
Current Year Plugging Costs Incurred		(9,428	)
Current Year Accretion Expense		143,882
Total Asset Retirement Obligation	$	1,619,576

New Accounting Pronouncements

On March 30, 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for the Company beginning January 1, 2005, and was applied in estimating the asset retirement obligation at December 31, 2005.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies that use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: (1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling, and (3) an aging of exploratory well costs suspended for greater than one year with the

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FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

number of wells it is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Application of this pronouncement did not have a significant impact on the Company’s financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” a replacement of APB Opinion No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements”. As of January 1, 2006, the Company adopted SFAS 154 which requires retrospective application of voluntary changes in accounting principles, unless it is impracticable to do so. The implementation of the standard did not have an impact on the Company’s results of operations and financial condition.

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and 140)” (“SFAS 155”). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Consequently, the Company will adopt the provisions of SFAS 155 for its year beginning January 1, 2007. The Company is currently evaluating the effect that the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In June 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 31, 2006. Consequently, the Company will adopt the provisions of FIN 48 for its year beginning January 1, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require or permit assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the

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FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. The Company does not expect that adoption of this FASB Staff Position will have a material impact on its results of operations or financial position.

2. CONCENTRATIONS OF CREDIT RISK

At times during the year ended December 31, 2006, the Company’s cash balance may have exceeded the Federal Deposit Insurance Corporation’s insured limit of $100,000. There were no losses incurred due to concentrations.

By using derivative instruments to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative is positive, the counterparty owes the Company, which creates repayment risk. The Company minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.

3. HEDGING ACTIVITIES

The Company’s results of operations and operating cash flows are impacted by changes in market prices for oil. To mitigate a portion of the exposure to adverse market changes, it entered into oil hedges. As of December 31, 2006, the Company’s oil hedging instruments consisted of fixed price swaps. These instruments allow the Company to predict with greater certainty the effective oil price to be received for its hedged production.

The Company sells oil in the normal course of its business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in oil sales. The Company enters into derivative instruments such as swap contracts to hedge a portion of its forecasted oil sales.

The Company received net hedge settlements of $91,335 under its hedges during the initial period ended December 31, 2006, which increased operating revenue. Unrealized losses associated with these fixed rate swaps contracts are included in operating revenue and amounted to $1,205,267 for the initial period ended December 31, 2006. Below is a summary of the Company’s open asset/ (liability) hedging positions as of December 31, 2006:

Type	Notional Volume (Bls)	Period	Fixed Price		Fair Market Value
Swap Contracts	216,000	1/1/07–12/31/07	$	65.00	$	15,633
Total Current Portion	216,000				$	15,633
Swap Contracts	204,000	1/1/08–12/31/08	$	65.58	$	(252,948	)
Swap Contracts	192,000	1/1/09–12/31/09	$	64.00		(426,433	)
Swap Contracts	180,000	1/1/10–12/31/10	$	62.20		(541,519	)
Total Long-Term Portion	576,000				$	(1,220,900	)
Total Financial Instruments	792,000				$	(1,205,267	)

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NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

4. REVOLVING LINE OF CREDIT FACILITY

The Company entered into a Credit Agreement dated as of October 2, 2006 with KeyBank National Association (“KeyBank”), as Administrative Agent on behalf of signatory lenders which are parties to the agreement from time to time. The credit facility established under the Credit Agreement provides for loans and letters of credit of up to a maximum of $40,000,000. Under the new credit facility, the Company may borrow funds under an alternative base rate or Eurodollar rate. Under the alternative base rate, the Company may borrow funds at a rate per annum equal to the greater of (i) the prime rate in effect on such day (which is defined as the rate of interest per annum publicly announced from time to time by KeyBank as its prime rate in effect at its principal office) and (ii) the Federal Funds Effective Rate (which is defined as the weighted average of the rates on overnight Federal fund transactions with members of the Federal Reserve System) in effect on such day plus  ¹/2 of 1%. Under the Eurodollar rate, the Company may borrow funds a rate per annum equal to the LIBO rate for such period multiplied by the statutory reserve rate. The statutory reserve rate is calculated as a fraction, the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the applicable maximum reserve percentages expressed as a decimal established by the Federal Reserve Board for eurocurrency funding. Borrowings under the new credit facility mature on the earlier to occur of (i) the next business day following the closing date of a new senior credit facility to be entered into by an affiliate of the Company pursuant to that certain commitment letter between Rex Energy Operating Corp., an affiliate of the Company, and KeyBank dated September 29, 2006, (ii) the next business day following the date of the issuance of equity interests by the Company or an affiliate of the Company in an initial public offering or (iii) April 2, 2007. Provided that certain conditions under the credit agreement are met, the Company may at any time and from time to time repay outstanding borrowings under the new credit facility, in whole or in part.

Borrowings under the new credit facility are currently secured by all of the Company’s oil and gas properties, including the Illinois and Indiana Properties described in Note 1. The Credit Agreement requires that at all times assets secured under the credit agreement represent at least 75% of the total value of the Company’s oil and gas properties. The Credit Agreement requires the Company to meet certain quarterly financial covenants and ratios, including total debt to EBITDAX (which is defined as consolidated net income plus expenses and charges, to the extent deducted from consolidated net income, of interest, income taxes, depreciation, depletion, amortization, exploration expenses and other similar noncash charges, minus all noncash income added to consolidated net income), and consolidated current assets to consolidated current liabilities. In addition, the Company must meet certain requirements regarding quarterly and annual financial reporting and semi-annual oil and gas reserve reporting. The Credit Agreement also contains non-financial covenants, which restrict the action of the Company with respect to certain matters, including the incurrence of additional indebtedness, payment of dividends and distributions, sale of the Company’s assets, the making of investments, transactions with affiliated companies, and the creation of additional liens on the assets of the Company.

The Credit Agreement requires that if either (i) the Company has not obtained a commitment for financing sufficient to fully and timely repay borrowings under the credit facility or (ii) if the borrowings under the credit facility have not been paid in full by March 12, 2007, upon notice by the administrative agent, the Company must cause the issuance and sale of its subordinated notes on a date which is no later than April 2, 2007 upon such terms and conditions as specified by the administrative agent. The proceeds of the subordinated notes must be used to repay borrowings under the new credit facility. The interest rates for the subordinated notes (whether floating or fixed) will be determined by the administrative agent with the approval of the Company (such approval not to be unreasonably withheld or delayed) in light of the then prevailing market conditions for comparable securities of comparable issuers. All other arrangements with respect to the subordinated notes must be reasonably satisfactory in all respects to the administrative agent in light of the then prevailing market conditions and the net cash proceeds of the sale of such subordinated notes must be sufficient to repay all amounts due under the Credit Agreement.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

On October 1, 2006, the Company borrowed $36,580,634 under the new credit facility to pay the purchase price for the acquisition of the Illinois and Indiana Properties from Tsar (See Note 1). At December 31, 2006, the outstanding balance on the line of credit was $37,580,634, of which $37,000,000 incurred interest at 8.35 percent and $580,634 incurred interest at 10.25 percent.

As of December 31, 2006, the Company was not in compliance with the negative covenant in its credit agreement requiring that its ratio of total debt to EBITDAX, as defined above, shall not exceed 5.5:1. On March 9, 2007, the Company obtained a written waiver from KeyBank of this covenant for the fourth quarter of 2006.

5. COMMITMENTS AND CONTINGENCIES

Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. The Company conducts periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort. Other than those matters described in Note 13, management knows of no significant probable or possible environmental contingent liabilities.

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company has not experienced any significant environmental liability, and, except as noted below, is not aware of any potential environmental issues or claims as of December 31, 2006.

At December 31, 2006, the Company’s Balance Sheet included reserves for the legal proceedings detailed below and at Note 13 of $391,000. The accrual of reserves for legal matters is included in Accrued Expenses on the Balance Sheet. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional loss, the amount of which is not currently estimable, in excess of the amounts currently accrued with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in actual liability exceeding the estimated ranges of loss and the amounts accrued. Based on currently available information, the Company believes that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed current accruals by an amount that would have a material adverse effect on the consolidated financial position or results of operations of the Company, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

The Company owns an average 49.0 percent working interest in certain oil producing wells and related facilities and equipment located in the states of Illinois and Indiana, referred to herein as the “Illinois and Indiana Properties” (See Note 1). The operator of the Illinois and Indiana Properties is PennTex Resources Illinois, Inc. (“PennTex Illinois”), a Delaware corporation which is wholly owned by Lance T. Shaner, a voting member of the Company. PennTex Illinois owns an average 26.0 percent working interest in the Illinois and Indiana Properties. Rex Energy Operating Corp., a Delaware corporation controlled by Lance T. Shaner, provides certain management and administrative services to PennTex Illinois in the course of its operations of the Illinois and Indiana Properties.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

EPA Matter

In September 2006, the United States Department of Justice (“U.S. DOJ”) and the United States Environmental Protection Agency (“U.S. EPA”) initiated an enforcement action against Rex Operating and PennTex Illinois seeking mandatory injunctive relief and potential civil penalties based on allegations that the companies were violating the Clean Air Act in connection with the release of hydrogen sulfide (H2S) gas and other volatile organic compounds (“VOC’s”) in the course of oil operations associated with the Illinois and Indiana Properties near the towns of Bridgeport, Illinois and Petrolia, Illinois. The senior management of PennTex Illinois and Rex Operating and representatives of the U.S. EPA, U.S. DOJ, Illinois Environmental Protection Agency (“Illinois EPA”) and the Agency for Toxic Substances and Disease Registry (“ATSDR”) attended a meeting at the offices of the U.S. EPA in Chicago, Illinois on September 7, 2006, to discuss matters relating to the enforcement action. This meeting had been preceded by certain monitoring of air emissions in the areas surrounding Bridgeport, Illinois and Petrolia, Illinois that the U.S. EPA and ATSDR had conducted in May 2006.

As a result of the initial meeting with the government on September 7, 2006, and certain subsequent meetings and communications between the senior management of PennTex Illinois and Rex Operating, on the one hand, and the U.S. EPA and U.S. DOJ, on the other, Rex Operating and PennTex Illinois executed a non-binding agreement in principle with the U.S. EPA effective October 24, 2006. In the agreement in principle, Rex Operating and PennTex Illinois agreed to develop and carry out a written response plan designed to further reduce possible emissions of H2S and VOC’s from the oil wells and facilities that are closest to populated areas. Rex Operating and PennTex Illinois agreed to operate and maintain the control measures described in the response plan in accordance with a written operations and maintenance plan to be developed by the companies and approved by the U.S. EPA. The agreement in principle also required the companies to evaluate the effectiveness of the control measures in the Illinois and Indiana Properties installed pursuant to the response plan through a monitoring program, and required the companies to evaluate the need for additional control measures at other facilities within 60 days. The companies also agreed to present to the U.S. EPA any recommendations for further action the companies might develop based upon their observations of the effectiveness of the control measures. Rex Operating, PennTex Illinois and the U.S. EPA each agreed that they would use their best efforts to negotiate a proposed final settlement agreement that would resolve the government’s enforcement action, which settlement agreement would be published in the Federal Register and made subject to public comment prior to any final approval.

The senior management of Rex Operating and PennTex Illinois, on the one hand, and the U.S. EPA and U.S. DOJ, on the other, are negotiating the terms of a comprehensive consent decree in which Rex Operating and PennTex Illinois, without any admission of wrongdoing or liability and without any agreement to pay any civil fine or penalty, would agree to install certain control measures and to implement certain operating and maintenance procedures regarding Illinois and Indiana Properties. Under the terms of the proposed consent decree, the companies would also agree to establish a monitoring protocol that would be designed to facilitate the reduction of possible emissions of H2S and VOC’s from the operations near Bridgeport, Illinois and Petrolia, Illinois. While at this time the Company is unable to predict with certainty the outcome of this enforcement action and the final terms and conditions of the consent decree, it believes that Rex Operating and PennTex Illinois will be able to reach a final settlement with the government agencies. The Company also believes that the consent decree will not require Rex Operating, PennTex Illinois or the Company to pay any civil fine or penalty, although it will provide for the possible imposition of specified daily fines and penalties for any days in which it might be determined that Rex Operating or PennTex Illinois have violated the terms and conditions of the consent decree. Any proposed consent decree will ultimately require the approval of a court of proper jurisdiction.

F-381

REX ENERGY IV, LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

The Company owns non-operated working interests in the same oil wells and related facilities operated by PennTex Illinois that are the subject of this enforcement action. While the Company is not the subject of this enforcement action, in the event that the Company does become a party to the enforcement action, the Company intends to vigorously defend itself in this matter. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss in this matter should the outcome be unfavorable.

Leib Case

Rex Energy and PennTex Illinois are defendants in a putative class action lawsuit that has been filed in the United States District Court for the Southern District of Illinois, Cause Number 3:06-CV-00802-JPG-CJP, styled “Julia Leib, et al. v. Rex Energy Operating Corp., et al.” This action was commenced on October 17, 2006, by plaintiffs, Julia Leib and Lisa Thompson, individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport, Illinois and Petrolia, Illinois. The complaint asserts that the operation of oil wells which are a part of the Illinois and Indiana Properties and that are controlled, owned or operated by Rex Operating and PennTex Illinois has resulted in “serious contamination” of the class area with H2S. The complaint asserts several causes of action, including violation of the Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct. The complaint seeks, among other things, injunctive relief under the Illinois Environmental Protection Act and Illinois common law, compensatory and other damages, punitive damages, and attorneys’ fees and costs. In addition, the complaint seeks the creation of a court-supervised, defendant-financed fund to pay for medical monitoring for the plaintiffs and others in the class area. On November 14, 2006, Rex Operating and PennTex Illinois filed a joint answer to the complaint specifically denying virtually all of the allegations in the complaint and asserting affirmative defenses thereto. On December 20, 2006, the plaintiffs filed a motion for class certification requesting that the court certify the case as a class action. Rex Operating and PennTex Illinois intend to vigorously oppose the plaintiffs’ motion for certification of the case as a class action.

The Company owns non-operated working interests in the same oil wells and related facilities operated by PennTex Illinois that are the subject of this lawsuit. The Company is not a party to the lawsuit and the Company intends to vigorously oppose any attempts to join it as a defendant in the lawsuit. In the event that the Company is joined as a defendant in this lawsuit, the Company intends to vigorously defend itself in this matter. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss in this matter should the outcome be unfavorable.

6. RELATED PARTY TRANSACTIONS

The Company’s 50.0 percent voting member, Lance T. Shaner, is the sole stockholder of PennTex Resources Illinois, Inc., a Delaware corporation (“PennTex Illinois”) and is the sole limited partner and controls the general partner of PennTex Resources, L.P., a Texas limited partnership (“PennTex LP”). PennTex LP and PennTex Illinois own average working interests of 25.0 percent and 26.0 percent, respectively, in the Illinois and Indiana Properties. PennTex Illinois is the operator of the Illinois and Indiana Properties, and as operator, charged $480,575 of overhead charges to the Company for the initial period ended December 31, 2006.

At December 31, 2006, there is a related party receivable due in the amount of $47,039, primarily related to an advance given to PennTex Resources Illinois, Inc. At December 31, 2006, there is a related party payable in the amount of $8,877 to Rex Energy Operating Corp.

The Company is owed capital contributions related to the formation of the Rex IV in the amount of $100, which is included in Other Receivables.

F-382

REX ENERGY IV, LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

Refer to Note 1 under Organization and Description of Business for additional related party information.

7. MAJOR CUSTOMER

The Company sold 100.0 percent of its oil production in the Indiana and Illinois Properties to Countrymark Cooperative, LLP in 2006.

8. FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107, “Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments.

The fair value of the liability associated with the Company’s hedging instruments is $1,205,267 at December 31, 2006. The fair value is based on valuation methodologies of its counterparty. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

9. COSTS INCURRED IN OIL ACQUISITION AND DEVELOPMENT ACTIVITIES

Costs incurred by the Company in its oil property acquisitions and developments are presented below and include the acquisition described in Note 1:

	2006
Oil Property Acquisition Costs	$	36,595,479
Development Costs		835,431
Total	$	37,430,910

Property acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather oil.

10. OIL PROPERTY CAPITALIZED COSTS

Aggregate capitalized costs for the Company related to oil production activities with applicable accumulated depreciation and depletion are presented below:

	2006
Proved Oil Properties	$	28,895,479
Well Development Costs		8,535,431
Capitalized Asset Retirement Obligation Costs		1,485,122
Total		37,430,910
Less: Accumulated Depreciation and Depletion		(1,064,648	)
Total	$	36,366,262

F-383

REX ENERGY IV, LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

11. RESULTS OF OIL PRODUCING ACTIVITIES

The results of operations for oil producing activities (excluding overhead and interest costs) are presented below:

	2006
Revenue
Oil Sales	$	3,993,490
Realized Gains on Hedges		91,335
Unrealized Loss on Hedges		(1,205,267	)
Net Oil Sales		2,879,558
Expenses
Operating Expenses		2,393,285
Production Taxes		28,246
Accretion Expense on Asset Retirement Obligation		143,882
Depreciation and Depletion		1,064,648
Total Expenses		3,630,061
Results of Operations for Oil Producing Activities	$	(750,503	)

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, and other production taxes. In addition, production costs include administrative expenses applicable to support equipment associated with these activities.

Depreciation and depletion expense includes those costs associated with capitalization acquisitions and development costs, but does not include the depreciation applicable to support equipment.

There is no provision for income taxes because the Company is a nontaxable entity.

12. OIL RESERVE QUANTITIES (UNAUDITED)

The Company’s independent engineers, Netherland, Sewell and Associates, Inc., have evaluated the Company’s proved reserves associated with the mineral leases and wells located in Indiana and Illinois

The Company emphasizes that reserve estimates are inherently imprecise. Its oil reserve estimates of properties located in Indiana and Illinois were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

Proved oil reserves represent the estimated quantities of oil which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by oil and natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be

F-384

REX ENERGY IV, LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

Presented below is a summary of changes in estimated reserves of the oil wells located in Illinois and Indiana at December 31, 2006:

	Oil (bls)
Proved Reserves—Beginning of Period	0
Purchases of Reserves in Place	3,919,064
Production	(71,699	)
Proved Reserves—End of Period	3,847,365
Proved developed reserves
December 31, 2005	—
December 31, 2006	3,141,002

13. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

Statement of Financial Accounting Standard No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proven reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0 percent annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth the Company’s future net cash flows relating to proved oil reserves based on the standardized measure prescribed by SFAS 69 at December 31, 2006:

Future Cash Inflows		(a)  $  218,186,400
Future Production Costs		(131,875,200	)
Future Abandonment Costs		(3,803,749	)
Future Development Costs		(7,163,700	)
Net Future Cash Inflows		75,343,751
Less: Effect of a 10.0% Discount Factor		(27,429,727	)
Standardized Measure of Discounted Future Cash Flows	$	47,914,024

(a) Calculated using weighted average prices of $56.71 per barrel of oil.

F-385

REX ENERGY IV, LLC

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE INITIAL PERIOD OCTOBER 1, 2006 TO DECEMBER 31, 2006

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

Standardized Measure—Beginning of Period	$	0
Purchases of Reserves in Place		48,566,512
Sale of Product—Net of Production Costs		(1,509,505	)
Development Costs Incurred		857,017
Standardized Measure—End of Period	$	47,914,024

14. SUBSEQUENT EVENTS

On January 26, 2007, the United States District Court for the Southern District of Illinois, in the case of the putative class action lawsuit filed against Rex Operating and PennTex Illinois (See Note 5), issued a scheduling and discovery order establishing deadlines for completing discovery and briefing relating to the plaintiffs’ motion for class certification. The order states that after the filing of the last brief on class certification issues on August 31, 2007, the court will schedule a hearing on plaintiffs’ motion for class certification. Rex Operating and PennTex Illinois intend to vigorously oppose the plaintiffs’ motion for certification of the case as a class action. On January 31, 2007, the plaintiffs in the above action filed a motion for leave seeking permission to file an amended complaint that would add a claim against the defendants for alleged violation of Section 7002(a)(1) of the Resource Conservation And Recovery Act (“RCRA”). Plaintiffs’ proposed amended complaint makes factual allegations similar to those previously asserted in Plaintiffs’ prior pleadings. The Company believes that it is likely that the court will grant Plaintiffs’ leave to file the amended complaint. On February 6, 2007, the court set a final pretrial conference for this case for August 7, 2008. The case is scheduled for jury trial on August 18, 2008, in the United States District Court for the Southern District of Illinois located in Benton, Illinois. The parties to this lawsuit have exchanged initial pretrial disclosures as required under the applicable rules and each side has served and responded to pre-deposition written discovery.

As of December 31, 2006, the Company was not in compliance with the negative covenant in its credit agreement requiring that its ratio of total debt to EBITDAX, as defined in the credit agreement, shall not exceed 5.5:1. On March 9, 2007, the Company obtained a written waiver from KeyBank of this covenant for the fourth quarter of 2006. Unless certain other events occur before such date, the current maturity date of loans under the credit agreement is April 2, 2007 (See Note 4). The Company is currently conducting negotiations with KeyBank, as administrative agent under the credit agreement, to extend the maturity date of loans under the credit agreement for a period of up to one year.

F-386

Oil Property acquired from Tsar Energy II, LLC

F-387

INDEPENDENT AUDITORS’ REPORT

To the Members of

Rex Energy IV, LLC

State College, PA

We have audited the accompanying statements of revenues and direct operating expenses of the oil property acquired from Tsar Energy II, LLC for the period January 1, 2006 through September 30, 2006, the year ended December 31, 2005, and the period March 1, 2004 through December 31, 2004. These financial statements are the responsibility of Rex Energy IV, LLC’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the statements of revenue and direct operating expenses are free of material misstatement. An audit of a statement of revenues and direct operating expenses includes examining, on a test basis, evidence supporting the amounts and disclosures in that financial statement. An audit of a statement of revenues and direct operating expenses also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits of the statements of revenues and direct operating expenses provide a reasonable basis for our opinion.

The accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and exclude material expenses, as described in Note 1 to the financial statements, that would not be comparable to those resulting from the proposed future operations of the oil properties and is not intended to be a complete presentation of revenues and expenses.

In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects the revenues and direct operating expenses of the oil property acquired from Tsar Energy II, LLC as described in Note 1 for the period January 1, 2006 through September 30, 2006, the year ended December 31, 2005, and the period March 1, 2004 through December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

Malin, Bergquist & Company, LLP

Pittsburgh, PA

April 19, 2007

F-388

REX ENERGY IV, LLC

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES—

OIL PROPERTY ACQUIRED FROM TSAR ENERGY II, LLC

FOR THE PERIOD JANUARY 1, 2006 THROUGH SEPTEMBER 30, 2006

AND

FOR THE YEAR ENDED DECEMBER 31, 2005

AND

FOR THE PERIOD MARCH 1, 2004 THROUGH DECEMBER 31, 2004

	2006		2005		2004
Revenues—oil sales	$	14,500,898	$	16,988,506	$	11,192,447
Direct operating expenses		7,241,261		10,178,656		7,834,774
Excess of revenues over direct operating expenses	$	7,259,637	$	6,809,850	$	3,357,673

SEE ACCOMPANYING NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES.

F-389

REX ENERGY IV, LLC

(OIL PROPERTY ACQUIRED FROM

TSAR ENERGY II, LLC)

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD JANUARY 1, 2006 THROUGH SEPTEMBER 30, 2006

AND FOR THE YEAR ENDED DECEMBER 31, 2005

AND FOR THE PERIOD MARCH 1, 2004 THROUGH DECEMBER 31, 2004

Note 1. BASIS OF PRESENTATION

The accompanying financial statements present the revenues and direct operating expenses of the oil property (the Property) acquired from Tsar Energy II, LLC (Tsar) for the period January 1, 2006 through September 30, 2006, the year ended December 31, 2005, and the period March 1, 2004 through December 31, 2004. The property was purchased by Rex Energy IV, LLC (the Company) on October 1, 2006 for approximately $35 million. The Property consists of working and royalty interests.

The accompanying statements of revenues and direct operating expenses of the Property do not include general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes since historical expenses of this nature incurred by Tsar are not necessarily indicative of the costs to be incurred by the Company.

Revenues in the accompanying statements of revenues and direct operating expenses are recognized on the entitlement method. Direct operating expenses are recognized on the accrual basis and consist of monthly operator overhead costs and other direct costs of operating the Property which were charged to the joint account of working interest owners by the operator of the wells. Direct operating expenses include all costs associated with production, marketing and distribution, including all selling and direct overhead other than costs of general corporate activities.

Historical financial information reflecting financial position, results of operations, and cash flows of the Property is not presented because the purchase price was assigned to the oil property interests and related equipment acquired. Other assets acquired and liabilities assumed were not material. In addition, the Property was a part of a larger enterprise prior to the acquisition by the Company, and representative amounts of general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the Property acquired, nor would such allocated historical costs be relevant to future operations of the Property. Development and exploration expenditures related to the Property were insignificant in the relevant periods. Accordingly, the historical statements of revenues and direct operating expenses of Tsar’s interest in the Property are presented in lieu of the financial statements required under Item 3-05 of Securities and Exchange Commission Regulation S-X.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Note 2. SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL PRODUCING ACTIVITIES (UNAUDITED)

The following reserve estimates present the Company’s estimate of the proven oil reserves and net cash flow of the Property which is a United States property.

The Company emphasizes that reserve estimates are inherently imprecise. Our oil reserve estimates of wells located in Indiana and Illinois were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available.

F-390

REX ENERGY IV, LLC

(OIL PROPERTY ACQUIRED FROM

TSAR ENERGY II, LLC)

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD JANUARY 1, 2006 THROUGH SEPTEMBER 30, 2006

AND FOR THE YEAR ENDED DECEMBER 31, 2005

AND FOR THE PERIOD MARCH 1, 2004 THROUGH DECEMBER 31, 2004

Proved oil reserves represent the estimated quantities of oil which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by oil and natural gas and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

(a) Reserve Quantity Information

Presented below is a summary of changes in estimated reserves of the oil wells at September 30, 2006 and December 31, 2005 and 2004. The reserves are proved.

	September 30 2006		December 31 2005		December 31 2004
	Oil(bls)
Proved Reserves—Beginning of Period	4,520,817		1,789,580		2,443,250
Plus/(Minus) Revisions of Previous Estimates	(307,441	)	3,098,477		(346,101	)
Production	(228,289	)	(367,240	)	(307,569	)
Proved Reserves—End of Period	3,985,087		4,520,817		1,789,580

(b) Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves

The standardized measure of discounted future net cash flows relating to proved oil reserves (Standardized Measure) is a disclosure requirement under Statement of Financial Accounting Standard No. 69.

The Standardized Measure does not purport to be, nor should it be interpreted to present, the fair value of the oil reserves of the Property. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs are based on period-end sales prices for oil, estimated future production of proved reserves and estimated future production and development costs of proved reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

F-391

REX ENERGY IV, LLC

(OIL PROPERTY ACQUIRED FROM

TSAR ENERGY II, LLC)

NOTES TO FINANCIAL STATEMENTS—(Continued)

FOR THE PERIOD JANUARY 1, 2006 THROUGH SEPTEMBER 30, 2006

AND FOR THE YEAR ENDED DECEMBER 31, 2005

AND FOR THE PERIOD MARCH 1, 2004 THROUGH DECEMBER 31, 2004

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The standardized measure of discounted future net cash flows relating to proved oil reserves is as follows at September 30, 2006 and December 31, 2005 and 2004:

	September 30 2006			December 31 2005			December 31 2004
Future Cash Inflows	(a)$	232,968,234		$	255,648,565		$	51,002,995
Future Production Costs		(136,395,300	)		(133,491,084	)		(43,619,777	)
Future Development Costs		(7,544,531	)		(7,746,612	)		0
Net Future Cash Inflows		89,028,403			114,410,869			7,383,218
Less: Effect of 10% Discount Factor		(34,131,247	)		(49,772,279	)		(1,406,448	)
Standardized Measure of Discounted Future Net Cash Flow	$	54,897,156		$	64,638,590		$	5,976,770

(a) Calculated using weighted average prices per barrel of oil of $58.46 at September 30, 2006, $56.55 at December 31, 2005, and $28.50 at December 31, 2004.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

	September 30 2006			December 31 2005			December 31 2004
Standardized Measure—Beginning of Period	$	64,638,590		$	5,976,770		$	10,732,265
Sales of Oil Produced—net of production costs		(7,259,637	)		(6,809,850	)		(3,357,673	)
Net Changes in Prices and Production costs		1,119,589			22,620,558			(2,620,370	)
Changes in future development costs		124,608			(4,376,595	)		0
Revisions in previous quantity estimate		(4,594,104	)		41,613,761			(1,152,560	)
Accretion of Discount		6,463,859			597,677			1,073,227
Changes in timing and other		(5,595,750	)		5,016,269			1,301,882
Standardized Measure—End of Period	$	54,897,156		$	64,638,590		$	5,976,770

Estimates of economically recoverable oil reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geological formations and other matters. Actual quantities of oil may differ materially from the amounts estimated.

F-392

APPENDIX A

NETHERLAND, SEWELL & ASSOCIATES, INC. RESERVE REPORT

[Netherland, Sewell & Associates Letterhead]

February 22, 2007

Mr. Benjamin W. Hulburt

Rex Energy Operating Corporation

1975 Waddle Road

State College, Pennsylvania 16803

Dear Mr. Hulburt:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2006, to the interest of Douglas Oil & Gas, Limited Partnership; Douglas Westmoreland, Limited Partnership; Midland Exploration, Limited Partnership; Penntex Resources Illinois, Inc.; Penntex Resources LP; Rex Energy, Limited Partnership; Rex Energy II, Limited Partnership; Rex Energy II Alpha, Limited Partnership; Rex Energy III, LLC; Rex Energy IV, LLC; and Rex Energy Royalties, Limited Partnership (collectively referred to herein as “Rex Energy et al.”) in certain oil and gas properties located in the United States, as listed in the accompanying tabulations. This report has been prepared using constant prices and costs, as discussed in subsequent paragraphs of this letter. The estimates of reserves and future revenue in this report conform to the guidelines of the U.S. Securities and Exchange Commission (SEC).

As presented in the accompanying summary projections, Tables I through IV, we estimate the net reserves and future net revenue to the Rex Energy et al. interest in these properties, as of December 31, 2006, to be:

	Net Reserves		Future Net Revenue ($)
Category	Oil (Barrels)	Gas (MCF)	Total	Present Worth at 10%
Proved Developed
Producing	08,013,139	09,763,201	239,410,600	143,884,400
Non-Producing	01,281,670	01,603,222	039,775,300	024,059,700
Proved Undeveloped	02,299,213	05,846,434	073,245,000	032,317,300
Total Proved	11,594,022	17,212,857	352,430,900	200,261,400

The oil reserves shown include crude oil and condensate. Oil volumes are expressed in barrels that are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of cubic feet (MCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. In accordance with SEC guidelines, our estimates do not include any probable or possible reserves that may exist for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserve categorization conveys the relative degree of certainty; the estimates of reserves and future revenue included herein have not been adjusted for risk. Definitions of reserve categories are presented immediately following this letter. As shown in the Table of Contents, for each reserve category this report includes a summary projection of reserves and revenue along with one-line summaries of reserves, economics, and basic data by lease.

Future gross revenue to the Rex Energy et al. interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deductions for these taxes, future capital costs, and operating expenses but before consideration of federal income taxes. In accordance with SEC guidelines, the future net revenue has been discounted at an annual rate of 10 percent to determine its “present worth.” The present worth is shown to

indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and their related facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Also, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

Oil prices used in this report are based on a December 31, 2006, West Texas Intermediate posted price of $57.75 per barrel and are adjusted by lease for quality, transportation fees, and regional price differentials. Gas prices used in this report are based on a December 31, 2006, Henry Hub spot market price of $5.635 per MMBTU and are adjusted by lease for energy content and regional price differentials. All prices are held constant in accordance with SEC guidelines.

Lease and well operating costs used in this report are based on operating expense records of Rex Energy Operating Corporation (Rex Energy). For nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, lease and well operating costs for the operated properties include only direct lease- and field-level costs. For all properties, headquarters general and administrative overhead expenses of Rex Energy et al. are not included. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers, new development wells, and production equipment.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Rex Energy et al. interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Rex Energy et al. receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. The reserves may or may not be recovered; if they are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. Also, estimates of reserves may increase or decrease as a result of future operations.

In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geologic. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geologic data; therefore, our conclusions necessarily represent only informed professional judgment.

The titles to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Rex Energy Operating Corporation, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting geologic, field performance, and work data are on file in our office. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties and are not employed on a contingent basis.

Very truly yours, NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ Frederic D. Sewell, P.E.
	Frederic D. Sewell, P.E. Chairman and Chief Executive Officer

By:	/s/ Matthew T. Brogdon, P.E.
	Matthew T. Brogdon, P.E. Vice President

Date Signed: February 22, 2007

MTB:KEA

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

APPENDIX B

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and gas industry terms used in this prospectus:

Basin. A large natural depression on the earth’s surface in which sediments accumulate.

Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, of crude oil.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

Bopd. Barrels of oil per day.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or gas.

Development of Developmental well. A well drilled within the proved boundaries of an oil or gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses, taxes and the royalty burden.

Exploitation. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but generally is expected to have lower risk.

Exploration or Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.

Injection well or Injection. A well which is used to place liquids or gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field.

Lease operating expenses. The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBOE. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet of natural gas.

Mcfd. One thousand cubic feet of natural gas per day.

MMBbls. One million barrels of oil or other liquid hydrocarbons.

MMBOE. One million barrels of oil equivalent.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of gas.

MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or gas liquids.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.

NYMEX. New York Mercantile Exchange.

PV-10 or present value of estimated future net revenues. An estimate of the present value of the estimated future net revenues from proved oil and gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the Securities and Exchange Commission’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and gas prices and operating costs at the date indicated and held constant for the life of the reserves.

Primary recovery. The period of production in which oil and natural gas is produced from its reservoir through the wellbore without enhanced recovery technologies, such as water floods or ASP floods.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed non-producing reserves or PDNP. Proved developed reserves expected to be recovered from zones behind casing in existing wells.

Proved developed producing reserves or PDP. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.

Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, gas and gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves or PUD. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The addition of production from another interval or formation in an existing wellbore.

Reserve life index. This index is calculated by dividing year-end proved reserves by the average production during the past year to estimate the number of years of remaining production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Secondary recovery. An artificial method or process used to restore or increase production from a reservoir after the primary production by the natural producing mechanism and reservoir pressure has experienced partial depletion. Gas injection and waterflooding are examples of this technique.

Tertiary recovery. The third stage of hydrocarbon production during which sophisticated techniques that alter the original properties of the oil are used. Chemical flooding (including ASP flooding), miscible displacement and thermal flooding are examples of this technique.

Tcf. Trillion cubic feet of gas.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether or not such acreage contains proved reserves.

Waterflooding. A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

Workover. Operations on a producing well to restore or increase production.

14,670,000 Shares

REX ENERGY CORPORATION

Common Stock

PROSPECTUS

KeyBanc Capital Markets

RBC Capital Markets

A.G. Edwards

Johnson Rice & Company L.L.C.

Pickering Energy Partners

Until                     , 2007 (25 days after the commencement of the offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

                                , 2007

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

The table below sets forth the estimated expenses expect to be paid by Rex Energy Corporation in connection with the issuance and distribution of the common stock being registered on this Form S-1, other than underwriting discounts and commission. All amounts are estimates except for the Securities and Exchange Commission registration fee, the National Association of Securities Dealers Inc. fee and the Nasdaq Global Market listing fee.

Securities and Exchange Commission registration fee	$  6,754
National Association of Securities Dealers Inc. fee	21,500
Nasdaq Global Market filing fee	5,000
Printing and engraving expenses	400,000
Accounting fees and expenses	190,000
Legal fees and expenses	1,120,000
Transfer agent and registrar fees	10,000
Miscellaneous fees and expenses	546,746
TOTAL	$2,300,000

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

Section 145 of the General Corporation Law of the State of Delaware provides as follows:

A corporation shall have the power to indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that the person is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interest of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent shall not, of itself, create a presumption that the person did not act in good faith and in a manner which the person reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had reasonable cause to believe that his conduct was unlawful.

A corporation shall have the power to indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that the person is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against expenses (including attorneys’ fees) actually and reasonably incurred by him in connection with the defense or settlement of such action or suit if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made with respect to any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the Court of Chancery or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Court of Chancery or such other court shall deem proper.

II-1

As permitted by the Delaware General Corporation Law, we have included in our amended and restated certificate of incorporation a provision to eliminate the personal liability of our directors for monetary damages for breach of their fiduciary duties as directors, subject to certain exceptions. In addition, our amended and restated certificate of incorporation and bylaws provide that we are required to indemnify our officers and directors under certain circumstances, including those circumstances in which indemnification would otherwise be discretionary, and we are required to advance expenses to our officers and directors as incurred in connection with proceedings against them for which they may be indemnified.

The underwriting agreement provides that the underwriters are obligated, under certain circumstances, to indemnify our directors, officers and controlling persons against certain liabilities, including liabilities under the Securities Act. Reference is made to the form of underwriting agreement filed as Exhibit 1.1 hereto.

We maintain directors and officers liability insurance for the benefit of our directors and officers.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

The transactions contemplated by the Reorganization Transactions will be completed simultaneously with the closing of this offering contemplated by this registration statement. In these transactions, the existing equity owners of each of Douglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, New Albany-Indiana, LLC, PennTex Resources, L.P., PennTex Resources Illinois, Inc., Rex Energy Limited Partnership, Rex Energy II Limited Partnership, Rex Energy III LLC, Rex Energy IV, LLC, Rex Energy II Alpha Limited Partnership, Rex Energy Operating Corp. and Rex Energy Royalties Limited Partnership, will receive an aggregate of 21,994,702 shares of our common stock in exchange for their respective equity interests. In so doing, the registrant relied on the provisions of Section 4(2) of, and Rule 506 under, the Securities Act in claiming exemption for the offering, sale and delivery of such securities from registration under the Securities Act.

ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a) Exhibits

Exhibit Number	Exhibit Title
1.1**	Form of Underwriting Agreement
2.1**	Agreement and Plan of Merger among New Albany-Indiana, LLC, , Rex Energy III LLC, Rex Energy I, LLC and Rex Energy Corporation
2.2**	Agreement and Plan of Merger among Douglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, Rex Energy Limited Partnership, Rex Energy II Limited Partnership, Rex Energy II Alpha Limited Partnership, Rex Energy Royalties Limited Partnership, Rex Energy I, LLC and Rex Energy Corporation
2.3**	Contribution Agreement among Lance T. Shaner, Benjamin W. Hulburt, Michael J. Carlson, Jack Shawver, Thomas F. Shields, Thomas C. Stably, Christopher K. Hulburt, PennTex Energy, Inc. and Rex Energy Corporation
3.1**	Certificate of Incorporation of Rex Energy Corporation
3.2**	Amendment to Certificate of Incorporation of Rex Energy Corporation
3.3**	Amended and Restated Bylaws of Rex Energy Corporation
4.1**	Form of Specimen Common Stock certificate of Rex Energy Corporation
4.2**	Form of Registration Rights Agreement
5.1**	Opinion of Fulbright & Jaworski L.L.P.
10.1**	Form of Rex Energy Corporation 2007 Long-Term Incentive Plan
10.2**	Form of Employment Agreement with Benjamin W. Hulburt and Thomas F. Shields

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Exhibit Number	Exhibit Title
10.3**	Form of Employment Agreement with Thomas C. Stabley and Christopher K. Hulburt
10.4**	Amended and Restated Employment Agreement, dated May 18, 2006, with Jack Shawver
10.5**	Consent Decree
10.6**	Independent Director Agreement with John A. Lombardi
10.7**	Service Provider Agreement, dated April 1, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp.
10.8**	Service Level Agreement, dated April 13, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp.
10.9**	Letter Agreement, dated April 13, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp.
10.10**	Lease Agreement, dated September 1, 2006, between Shaner Brothers, LLC and Rex Energy Operating Corp.
10.11**	Promissory Note, dated September 1, 2006, by Rex Energy Operating Corp. to Shaner Brothers, LLC
10.12**	Summary of oral month-to-month administrative services agreement between Shaner Solutions Limited Partnership and Rex Energy Operating Corp.
10.13**	Summary of oral month-to-month agreement regarding use of airplane between Charlie Brown Air Corp. and Rex Energy Operating Corp.
10.14**	Summary of oral working capital loan agreement between Lance T. Shaner and PennTex Resources Illinois, Inc.
10.15**	Amended and Restated Limited Liability Company Agreement, dated June 21, 2007, of L&B Air LLC
10.16**	Amended and Restated Limited Partnership Agreement, dated June 21, 2007, of Charlie Brown II Limited Partnership
10.17**	Promissory Note, dated June 21, 2007, by Rex Energy Operating Corp. to Lance T. Shaner
10.18**	First Amended and Restated Aircraft Joint Ownership and Management Agreement, dated June 21, 2007, between Charlie Brown Air Corp. and Charlie Brown II Limited Partnership
21.1**	Subsidiaries of Rex Energy Corporation
23.1*	Consent of Malin, Bergquist & Company, LLP
23.2*	Consent of Netherland, Sewell & Associates, Inc.
23.3**	Consent of Fulbright & Jaworski L.L.P. (included in Exhibit 5.1)
23.4**	Consent of Surtek, Inc.
24.1**	Powers of Attorney

* Filed herewith.

** Previously filed.

(b) Financial Statement Schedules

All schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.

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ITEM 17. UNDERTAKINGS.

The undersigned Registrant hereby undertakes:

(1) That for purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act of 1933 shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) That for the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) To provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

(4) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of State College and State of Pennsylvania on July 20, 2007.

REX ENERGY CORPORATION (Registrant)
By:	/S/    BENJAMIN W. HULBURT
Name:	Benjamin W. Hulburt
Title:	Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/S/    LANCE T. SHANER         Lance T. Shaner	Chairman	July 20, 2007
/S/    THOMAS F. SHIELDS         Thomas F. Shields	Director	July 20, 2007
* John A. Lombardi	Director	July 20, 2007
/S/    BENJAMIN W. HULBURT         Benjamin W. Hulburt	Chief Executive Officer and Director (Principal Executive Officer)	July 20, 2007
/S/    THOMAS C. STABLEY         Thomas C. Stabley	Chief Financial Officer (Principal Financial and Accounting Officer)	July 20, 2007

*By:	/S/    CHRISTOPHER K. HULBURT
	Christopher K. Hulburt Attorney-In-Fact

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EXHIBIT LIST

EXHIBITS AND FINANCIAL STATEMENTS SCHEDULES.

Exhibit Number	Exhibit Title
1.1**	Form of Underwriting Agreement
2.1**	Agreement and Plan of Merger among New Albany-Indiana, LLC, , Rex Energy III LLC, Rex Energy I, LLC and Rex Energy Corporation
2.2**	Agreement and Plan of Merger among Douglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, Rex Energy Limited Partnership, Rex Energy II Limited Partnership, Rex Energy II Alpha Limited Partnership, Rex Energy Royalties Limited Partnership, Rex Energy I, LLC and Rex Energy Corporation
2.3**	Contribution Agreement among Lance T. Shaner, Benjamin W. Hulburt, Michael J. Carlson, Jack Shawver, Thomas F. Shields, Thomas C. Stably, Christopher K. Hulburt, PennTex Energy Inc. and Rex Energy Corporation
3.1**	Certificate of Incorporation of Rex Energy Corporation
3.2**	Amendment to Certificate of Incorporation of Rex Energy Corporation
3.3**	Amended and Restated Bylaws of Rex Energy Corporation
4.1**	Form of Specimen Common Stock certificate of Rex Energy Corporation
4.2**	Form of Registration Rights Agreement
5.1**	Opinion of Fulbright & Jaworski L.L.P.
10.1**	Form of Rex Energy Corporation 2007 Long-Term Incentive Plan
10.2**	Form of Employment Agreement with Benjamin W. Hulburt and Thomas F. Shields
10.3**	Form of Employment Agreement with Thomas C. Stabley and Christopher K. Hulburt
10.4**	Amended and Restated Employment Agreement, dated May 18, 2006, with Jack Shawver
10.5**	Consent Decree
10.6**	Independent Director Agreement with John A. Lombardi
10.7**	Service Provider Agreement, dated April 1, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp.
10.8**	Service Level Agreement, dated April 13, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp.
10.9**	Letter Agreement, dated April 13, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp.
10.10**	Lease Agreement, dated September 1, 2006, between Shaner Brothers, LLC and Rex Energy Operating Corp.
10.11**	Promissory Note, dated September 1, 2006, by Rex Energy Operating Corp. to Shaner Brothers, LLC
10.12**	Summary of oral month-to-month administrative services agreement between Shaner Solutions Limited Partnership and Rex Energy Operating Corp.
10.13**	Summary of oral month-to-month agreement regarding use of airplane between Charlie Brown Air Corp. and Rex Energy Operating Corp.
10.14**	Summary of oral working capital loan agreement between Lance T. Shaner and PennTex Resources Illinois, Inc.

Exhibit Number	Exhibit Title
10.15**	Amended and Restated Limited Liability Company Agreement, dated June 21, 2007, of L&B Air LLC
10.16**	Amended and Restated Limited Partnership Agreement, dated June 21, 2007, of Charlie Brown II Limited Partnership
10.17**	Promissory Note, dated June 21, 2007, by Rex Energy Operating Corp. to Lance T. Shaner
10.18**	First Amended and Restated Aircraft Joint Ownership and Management Agreement, dated June 21, 2007, between Charlie Brown Air Corp. and Charlie Brown II Limited Partnership
21.1**	Subsidiaries of Rex Energy Corporation
23.1*	Consent of Malin, Bergquist & Company, LLP
23.2*	Consent of Netherland, Sewell & Associates, Inc.
23.3**	Consent of Fulbright & Jaworski L.L.P. (included in Exhibit 5.1)
23.4**	Consent of Surtek, Inc.
24.1**	Powers of Attorney

* Filed herewith.

** Previously filed.