Form S-1

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

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

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 of 1933, 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. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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.

The information in this prospectus is not complete and may be changed. We and the selling stockholders 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 jurisdiction where the offer or sale is not permitted.

We are selling 4,000,000 shares of common stock, and the selling stockholders are selling 4,000,000 shares of common stock. We will not receive any of the proceeds from the shares of common stock sold by the selling stockholders.

Our common stock is listed on the NASDAQ Global Market under the symbol “REXX”. On April 4, 2008, the last reported sales price for our common stock on the NASDAQ Global Market was $17.39.

Investing in our common stock involves risks. See “ Risk Factors” beginning on page 14 to read about factors you should consider before buying shares of our common stock.

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 1,200,000 additional shares from us 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 , 2008.

You should rely only on the information contained in or incorporated by reference in this prospectus. We and the selling stockholders have not, and the underwriters have not, authorized anyone to provide you with additional or different information. If anyone provides you with additional, different or inconsistent information, you should not rely on it. We and the selling stockholders are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information contained in or incorporated by reference in this prospectus is accurate as of any date other than the dates of this prospectus or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since those dates.

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 and the documents incorporated by reference into this prospectus before making an investment decision, especially the information presented under the headings “Risk Factors” and “Selected Historical Financial and Operating Data.”

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 “Predecessor Companies.”

On July 30, 2007, simultaneously with the consummation of our initial public offering, Rex Energy Corporation, through a series of mergers and reorganization transactions, which we refer to collectively herein as the “Reorganization Transactions,” acquired all of the operations of the Predecessor Companies. Unless otherwise indicated, all references to “Rex Energy Corporation,” “the Company,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation, together with the Predecessor 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 (1) have been adjusted to give effect to the Reorganization Transactions and (2) 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 have pursued 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. We were incorporated in the state of Delaware on March 8, 2007. We completed our initial public offering and the Reorganization Transactions in July 2007. Our common stock currently trades on the NASDAQ Global Market under the symbol “REXX”.

At December 31, 2007, our proved reserves had the following characteristics:

•

15.9 MMBOE;

•

81% crude oil;

•

78% proved developed; and

•

A reserve life index of approximately 15 years (based upon fourth quarter 2007 production).

At December 31, 2007, we operated approximately 2,341 wells. For the quarter ended December 31, 2007, we produced an average of 2,831 net BOE per day, composed 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 2,109 barrels of oil per day in 2007. In addition to our developmental shallow oil drilling and exploratory shale drilling projects in the Illinois Basin, we are in the process of implementing 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 the Appalachian Basin, we averaged net production of approximately 2.2 MMcf of natural gas per day in 2007 and are continuing to grow our reserves and production in the region through developmental shallow natural gas drilling and exploratory drilling, including our Marcellus Shale drilling projects. While we do not currently have proven reserves in the Marcellus Shale, as of April 7, 2008, we control approximately 64,000 gross (36,000 net) acres in areas of Pennsylvania, which we believe are prospective for the Marcellus Shale exploration.

In the Southwestern Region, we averaged net production of approximately 1.8 MMcfe per day in 2007 and currently have several active drilling and redevelopment projects within that region, including drilling projects in the Queen, Leonard, Canyon and San Andres formations. At December 31, 2007, we owned interests in 152 wells located in west Texas and southeast New Mexico and we operated 93 of these wells.

Our total operating revenues for the year ended December 31, 2007 were $57.8 million. Revenues were derived from $63.5 million in oil and natural gas sales and $452,000 in other revenues, partially offset by $6.2 million in realized losses on derivatives.

For the year ended December 31, 2007, we drilled 85 gross (68.3 net) wells. The wells drilled in 2007 include 57 that were productive, 10 gross (10 net) producer wells and 7 gross (7 net) injector wells related to our Lawrence Field ASP Flood Project, one well that was deemed to be a dry hole and 10 gross (3.8 net) exploratory wells that are still being evaluated, eight of which are New Albany Shale wells.

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	Annual 2007 Average Daily BOE	Total Proved MMBOE (As of December 31, 2007)	Percent of Total Proved MMBOE		PV-10 (As of December 31, 2007) (In Millions)⁽¹⁾		Total Net Undeveloped Acres (As of December 31, 2007)⁽²⁾
Illinois Basin	2,109	12.0	75.4	%	$	336.5	84,942
Appalachian Basin	359	2.1	13.3	%		25.9	18,115
Southwestern Region	294	1.8	11.3	%		29.7	1,486

Total	2,762	15.9	100.0	%	$	392.1	104,543

(1)

Represents the present value, discounted at 10% per annum (PV-10), of estimated future net cash flows 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 generally accepted accounting principles in the United States, or GAAP. At December 31, 2007, our standardized measure of discounted future net cash flows was $255.0 million. For an explanation of why we show PV-10 and a reconciliation of PV-10 to the 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.

Significant Accomplishments in 2007

During 2007, our significant accomplishments included:

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Successful completion of our initial public offering: We completed our initial public offering in July 2007.

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Financial Strength: We improved our balance sheet, reducing debt by more than $75 million since closing our initial public offering. Additionally, we established a new senior credit facility, which has provided us with an available line of credit of up to $75 million.

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Production Growth: We increased annual production by 30% from 772 MBOE in 2006 to just over 1.0 MMBOE in 2007.

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Financial Performance: Our revenue increased by 46% in 2007 over the previous year, and our EBITDAX, as defined on page 32 of this prospectus, grew by 39% over the previous year to $25.3 million.

•

Proven Reserves Growth: During 2007, we achieved a reserve replacement rate of 139%. Our proven reserves grew by 10% over the previous year to 15.9 MMBOE, and the present value of future cash flows before taxes, or PV-10, grew by 96% to $392.1 million.

•

Successful Drilling Program: In 2007, we drilled 57 gross developmental wells. Our overall success rate was 99%.

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Continued Expansion of Drilling Inventory: To continue to grow, the size of our prospect inventory must remain large. Our drilling inventory currently includes over 3,000 net potential drilling locations. During 2007, we expanded our acreage position in the Marcellus Shale play by approximately 40%. As of April 7, 2008, we controlled approximately 64,000 gross (36,000 net) acres in this emerging play in Pennsylvania. Over the remainder of 2008, we plan to continue to expand our position in the Marcellus Shale play as well as commence pilot operations in our Lawrence Field ASP Flood Project in the Illinois Basin. We are continuing to retain additional experienced technical professionals to assist us in these significant projects.

Plans for 2008

In November 2007, we established an initial capital budget of approximately $78 million in 2008, which equated to an increase of 95% over the 2007 capital expenditures. The 2008 initial capital budget plan reflected our plans to accelerate our Lawrence Field ASP Flood Project, to commence the testing of our acreage in Pennsylvania for the Marcellus Shale, and to continue to drill our developmental drilling projects in the Appalachian Basin, Illinois Basin and Southwestern Region.

On March 17, 2008, our board of directors approved an increase in our 2008 capital budget to $139 million. The increase was primarily the result of increased anticipated capital expenditures in our Marcellus Shale leasing activities from $4.5 million to $57.1 million, as well as an increase in anticipated drilling activities from $4.2 million to $8.9 million.

The following table summarizes our actual 2007 and our revised estimated 2008 capital expenditures ($ in millions). The estimated capital expenditures are dependent on a number of factors, including industry conditions and our drilling success, and are subject to change. We do not attempt to budget for future acquisitions of proved oil and gas properties.


	For the Years Ended December 31,
	2007 (actual)		2008 (estimated)
Capital Expenditures
Illinois Basin Conventional Oil Operations	$	14.8	$	16.5
Lawrence Field ASP Flood Project		4.5		29.9
Shale Projects		3.2		16.1
Appalachian Basin Operations		5.2		7.1
Southwestern Region Operations		4.0		9.9
Acquisitions of proved oil and gas properties		2.3		—
Acquisitions and leasing of undeveloped properties		5.4		58.6
Other Capital Expenditures		1.0		0.6

Total Capital Expenditures	$	40.4	$	138.7

Our Competitive Strengths

We believe our historical success has been, and future performance will be, directly related to the following combination of strengths that we believe 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:

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our Lawrence Field ASP Flood Project in Illinois (please see “Business—Properties—Illinois Basin— Lawrence Field ASP Flood Project”);

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our large acreage positions in two unconventional shale exploration projects, with approximately 64,000 gross (36,000 net) acres in Pennsylvania prospective for the Marcellus Shale (please see “Business—Properties—Appalachian Basin—Marcellus Shale”), and approximately 306,000 gross acres (92,000 net) in southern Indiana prospective for the New Albany Shale as of April 7, 2008 (please see “Business—Properties—Illinois Basin—New Albany Shale”);

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our conventional shallow natural gas drilling opportunities in the Appalachian Basin and our conventional shallow oil drilling opportunities in the Illinois Basin; and

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our oil and gas developmental and exploratory drilling and redevelopment projects in the Southwestern Region.

Market Leader in the Illinois Basin: We believe 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 may enhance our ability to continue making strategic acquisitions in the basin.

Experienced Management Team with a Proven Track Record: We feel we have significant technical and managerial experience in our core operating areas. Our technical team of geologists and engineers have an average of 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: As of March 31, 2008, we had approximately $38.2 million in debt outstanding, representing a 7.5% debt to market capitalization at March 31, 2008 and value of $16.64 per share. In addition, our senior credit facility had a borrowing capacity of $75 million as of March 31, 2008, of which approximately $36.8 million was available for working capital purposes or to fund new acquisitions. Lastly, we believe our oil and gas financial derivative activities enable us to achieve more predictable cash flows and reduce our exposure to short-term fluctuations in oil and natural gas prices while we continue to develop our properties.

Incentivized Management Ownership: As of March 31, 2008, our directors and officers beneficially owned approximately 52% of our outstanding common stock and are expected to own approximately 35% after completion of this offering. Therefore, we believe 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: Our strategy is to utilize and expand the technological expertise that has enabled us to achieve a drilling completion rate of approximately 94% 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: Our focus is to develop our asset base in each of our operating basins including:

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our Lawrence Field ASP Flood Project in Illinois;

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our Marcellus Shale natural gas play with approximately 64,000 gross (36,000 net) acres;

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our inventory of approximately 500 proved undeveloped locations and proved developed non-producing wells; and

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our New Albany Shale resource play with over 306,000 gross (92,000 net) acres.

Pursue Strategic Acquisitions and Joint Ventures: We plan to continue to acquire and lease additional oil and natural gas 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 joint venture partners and pursue strategic acquisitions.

Focus on Operations: We 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 can benefit from increased production in lower cost operations and through better use of our existing infrastructure over a larger number of wells.

can generate higher than anticipated returns. We also believe in maintaining a strong balance sheet and using commodity hedging. This allows us to be more opportunistic in lower price environments as well as providing more consistent financial results.

Equity Ownership and Incentive Compensation: We believe our performance is enhanced when our employees think and act like owners. To achieve this, we believe in rewarding and encouraging our employees through equity ownership in our company. As of March 31, 2008, our employees owned approximately 3.5 million shares of our common stock, representing 11.4% of our total outstanding shares of common stock.

Our Properties and Projects

Illinois Basin

In the Illinois Basin, we own 2,017 net wells, 99% of which we operate. As of April 7, 2008, we have approximately 356,000 gross (116,000 net) acres under lease, which includes our interests in the Lawrence Field and New Albany Shale. At December 31, 2007, the Illinois Basin had total proven reserves of approximately 12.0 MMBOE and a development inventory of 216 proven drilling locations and 172 proven recompletions.

Lawrence Field ASP Flood Project

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

The Lawrence Field is believed to have produced more than 400 million barrels of oil, representing approximately 40% of the estimated one billion barrels of original oil-in-place in the field 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. During the 1960s, 1970s and 1980s, surfactant polymer flood projects implemented in the Lawrence Field demonstrated increases in ultimate oil reservoirs by 15% to 21%.

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 by other companies in several fields around the world resulting in significant incremental recoveries of the original oil-in-place. Our Lawrence Field ASP Flood Project will use 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 2006, we engaged Surtek, Inc. (“Surtek”), an independent engineering firm specializing in the design and implementation of chemical oil recovery systems, to review and update the evaluation on the application of the ASP process to the Lawrence Field. During 2007, Surtek completed their linear and radial core flood analysis on the Cypress and Bridgeport sandstones, which in the laboratory, resulted in an oil recovery rate as high as 21% of the estimated original oil-in-place in the Cypress sandstone, and 24% of the original oil-in-place in the Bridgeport sandstone. These results were in line with our initial projections.

During 2006 and 2007, we drilled 18 wells in our two pilot areas, upgraded the pilot area production facilities, installed the production flow-lines to both pilot areas, installed the pilot injection pipelines, and began construction of the pilot area chemical injection plant. We plan to initiate injection of the ASP chemicals on the two pilots in the second quarter of 2008. 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 2009. While we are encouraged by initial laboratory results, our Lawrence Field ASP Flood Project is not a proved project nor are any of the potential reserves from this project considered proved at this time.

New Albany Shale

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. Of these wells, three wells drilled in 2006 were determined to be uneconomical and were expensed as dry holes in the fourth quarter of 2007, two have been tested and are awaiting pipeline connections, and six are still being evaluated to determine whether they will be economical to complete and produce and to design stimulation procedures, if required.

Appalachian Basin

As of April 7, 2008, we own approximately 557 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 44 proved undeveloped drilling locations with total reserves of 4.6 Bcf, and three locations with proved developed non-producing reserves totaling 177 MMcf. At April 7, 2008, we controlled approximately 78,000 gross (41,000 net) acres in the Appalachian Basin under lease, of which 43,000 gross (26,000 net) acres were undeveloped.

Proven reserves at December 31, 2007 were 12.7 Bcf, an increase of 2.4 Bcf, or 24%, from 2006. Annual production increased 11% over 2006. Capital expenditures in 2007 for drilling and facility development in the region were approximately $5.2 million, which funded the drilling of 24 gross (14 net) development wells, of which 21 gross (12 net) were productive and three gross (two net) were completed and producing during the first quarter of 2008. During 2007, the region achieved a 100% drilling success rate.

Marcellus Shale

A large portion of our property in Pennsylvania is located in areas where active exploration for the Marcellus Shale, by companies such as Range Resources Corporation (NYSE:RRC), Equitable Resources, Inc. (NYSE:EQT), EOG Resources, Inc. (NYSE:EOG) and Atlas Energy Resources, LLC (NYSE: ATN), is 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 75 to 150 feet on our acreage in southwestern and central Pennsylvania. As of April 7, 2008, we had interests in approximately 64,000 gross (36,000 net) Marcellus Shale prospective acres in these areas of Pennsylvania. During 2008, we began testing our acreage in these areas and continue to expand our acreage positions in this emerging play. As of April 7, 2008, we have drilled two vertical test wells in the Marcellus Shale, which are expected to be completed during the second quarter of 2008. We have not booked any proved reserves in the Marcellus Shale.

Southwestern Region

Our operations in our Southwestern Region include several producing oil and gas fields in Lea and Eddy Counties, New Mexico, Terrell County, Texas and other producing regions of western Texas. At December 31, 2007, we operated 93 wells, and owned interests in another 59 wells, in west Texas and southeast New Mexico. At April 7, 2008, we had approximately 15,000 gross (10,000 net) acres in the Southwestern Region under lease, of which approximately 1,900 gross (1,500 net) acres were undeveloped.

Proven reserves at December 31, 2007 were 1.8 MMBOE, a decrease of approximately 200 MBOE, or 10%, from 2006. On an annual basis, production decreased approximately 1% from 2006. Capital expenditures in 2007 for drilling and facility development in the region totaled approximately $4.0 million, which funded the drilling of one gross (0.8 net) development wells, and three gross (0.8 net) exploratory wells, of which, one gross (one net) was expensed as a dry hole in 2007, one gross (one net) is expected to be expensed as a dry hole in the first quarter of 2008 and one gross (one net) is still being evaluated to determine if it would be economical to produce. Capital expenditures in 2007 also funded the recompletion of 11 gross (8.8 net) wells. At April 7, 2008, the Southwestern Region had a development inventory of eight proven drilling locations and three proven recompletions.

Our Reserves

Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm, evaluated our reserves on a consolidated basis as of December 31, 2007. 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 consolidated and combined financial statements for the year ended December 31, 2007 included in our Annual Report on Form 10-K, which is incorporated herein by reference, in conjunction with the following reserve estimates.

The following table sets forth our estimated proved reserves at the end of each of the past three years:


	December 31,
	2007		2006		2005
Estimated Proved Reserves⁽¹⁾
Gas (Bcf)		18.5		17.2		16.1
Oil (MMBbls)		12.8		11.6		6.4

Total proved reserves (MMBOE)⁽²⁾		15.9		14.5		9.1

PV-10 Value (millions)⁽³⁾	$	392.1	$	200.3	$	148.1
Pro Forma Standardized Measure (millions)⁽⁴⁾	$	255.0	$	132.1	$	108.2

(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 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 cash flows before income tax of our estimated proved reserves. The estimated future cash flows 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, 2007. The estimated future production is priced at December 31, 2007, without escalation, using $92.50 per bbl and $6.795 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 Predecessor Companies was a flow-through entity for state and federal tax purposes, our historical standardized measure for the years 2005 and 2006 does not deduct state or federal taxes. In addition, during 2007, the Predecessor Companies were flow-through entities for state and federal tax purposes until the effective time of the Reorganization Transactions in July 2007, when they become taxable entities. Because of the Reorganization Transactions, we show pro forma standardized measure in the table above, which deducts state and federal taxes for each of the periods shown.

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 increased levels of production;

•

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; and

•

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.

The Offering

Common stock offered by us

4,000,000 shares (or 5,200,000 shares if the underwriters exercise their over-allotment option in full)

Common stock offered by selling stockholders

4,000,000 shares

Common stock to be outstanding immediately after completion of this offering⁽¹⁾

34,794,702 shares (or 35,994,702 shares if the underwriters exercise their over-allotment option in full)

Over-allotment option granted by us

1,200,000 shares

Use of proceeds

Based on an assumed offering price of $17.39 per share, which was the last reported sale price of our common stock on the NASDAQ Global Market on April 4, 2008, we expect the net proceeds from the sale of the shares offered by us, after deducting underwriting discounts and commissions and estimated offering expenses, to be approximately $64.4 million, or approximately $84.2 if the underwriters’ overallotment option is exercised in full. We intend to use the net proceeds from this offering to fund, in part, our capital expenditure program for 2008, including our Lawrence Field ASP Project and Marcellus Shale leasing and drilling activities, and for other corporate purposes. Pending those uses, we intend to use a portion of the net proceeds to repay borrowings under our senior credit facility and invest in short-term, investment grade, interest-bearing securities. We will then reborrow amounts from time to time under our senior credit facility as capital expenditures exceed our overnight investments and cash flow from operations in periods subsequent to this offering. See “Use of Proceeds.”

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

NASDAQ Global Market symbol

“REXX”

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 14 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 3,079,470 shares of common stock reserved for issuance under our 2007 Long-Term Incentive Plan. As of April 7, 2008, we have granted stock options and stock appreciation rights covering 963,200 shares of our common stock.

Summary Financial Data

The following table shows selected consolidated and combined financial data of Rex Energy Corporation and the Predecessor Companies for each of the periods indicated. The historical consolidated and combined financial data has been prepared for Rex Energy Corporation as of and for the year ended December 31, 2007. The historical combined financial data has been prepared for the Predecessor Companies as of and for the years ended December 31, 2006 and 2005. The historical consolidated and combined financial statements as of and for the years ended December 31, 2007, 2006 and 2005 are derived from the historical audited financial data of Rex Energy Corporation and the Predecessor Companies. All material intercompany balances and transactions have been eliminated. Because each of the Predecessor 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 for the years ended December 31, 2006 and 2005 and the seven month period ended July 31, 2007. Provision for income tax is presented for the five month period ended December 31, 2007. This information should be read in conjunction with the section of this prospectus entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated and combined financial statements and related notes as of December 31, 2007 and 2006 and for each of the years ended December 31, 2007, 2006 and 2005, incorporated by reference into 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 accounting principles generally accepted in the United States of America (“GAAP”), please see “Selected Historical Financial and Operating Data—Non-GAAP Financial Measures.”


	Rex Energy Corporation Consolidated and Combined			Rex Energy Corporation Combined Predecessor Companies
	Year Ended December 31, ($ and shares in Thousands)
	2007			2006			2005
Statement of operations data:
Operating Revenue:
Oil and Natural Gas Sales	$	63,525		$	43,596		$	29,518
Other Revenue		452			470			270
Realized Gain (Loss) from Derivatives		(6,198	)		(4,436	)		(7,930	)

Total Operating Revenue		57,779			39,630			21,858

Operating Expenses:
Production Lease Operating and Production Taxes		24,477			15,234			11,721
General and Administrative		8,587			6,212			3,789
Depletion, Depreciation, Amortization and Accretion		19,622			11,223			3,320
Exploration		2,948			—			107

Total Operating Expenses		55,634			32,669			18,937

Income from Operations		2,145			6,961			2,921

Other Income (Expenses):
Interest Income		15			94			444
Interest Expense		(5,646	)		(6,110	)		(1,697	)
Gain on Sale of Oil and Gas Properties		185			91			1,016
Unrealized Gain (Loss) from Derivatives		(26,250	)		5,043			(5,541	)
Other Income (Expense)		171			(132	)		216

Total Other Income (Expense)		(31,525	)		(1,014	)		(5,562	)

Net Income (Loss) Before Minority Interests and Income Tax		(29,380	)		5,947			(2,641	)
Minority Interests Share of (Net Income) Loss		6,152			(2,133	)		(2,304	)
Income Tax Benefit		7,017			—			—

Net Income (Loss)	$	(16,211	)	$	3,814		$	(4,945	)

Earnings per common share for the five month period ended December 31, 2007:
Net loss for the five month period ended December 31, 2007	$	(10,640	)
Basic and fully diluted earnings per common share	$	(0.35	)		—			—
Weighted average shares of common stock outstanding		30,795			—			—
Other Financial Data:
EBITDAX (before minority interests)	$	25,282		$	18,143		$	7,580
Cash Flow Data:
Cash provided by operating activities		17,555			12,920			9,527
Cash used in investing activities		(40,102	)		(94,446	)		(19,404	)
Cash provided by financing activities		23,032			79,438			9,772
Balance Sheet Data:
Cash and cash equivalents		1,085			600			3,188
Property and Equipment (net of accumulated depreciation, depletion and amortization)		217,532			133,631			42,265
Total Assets		268,264			144,611			55,291
Current liabilities, including current portion of long-term debt		20,736			53,684			32,297
Long-Term Debt, net of current maturities		27,207			45,442			3,360
Total Liabilities		103,827			108,639			42,080
Minority Interests		—			36,589			24,130
Owners’ Equity		164,437			(617	)		(10,920	)

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, ($ in Thousands)
	2007			2006			2005
Production
Oil (Bbls)		814,857			587,470			378,954
Natural gas (Mcf)		1,159,999			1,109,494			1,124,743
Oil equivalent (BOE)		1,008,190			772,386			566,411

Oil and natural gas sales⁽¹⁾
Oil sales	$	55,542		$	35,790		$	20,355
Natural gas sales		7,983			7,806			9,163

Total	$	63,525		$	43,596		$	29,518


Average sales price⁽¹⁾
Oil ($ per Bbl)	$	68.16		$	60.92		$	53.71
Natural gas ($ per Mcf)	$	6.88		$	7.04		$	8.15
Oil equivalent ($ per BOE)	$	63.01		$	56.44		$	52.11

Average production cost
Oil equivalent ($ per BOE)	$	24.28		$	19.72		$	20.70

Estimated proved reserves⁽²⁾
Oil equivalent (MMBOE)		15.9			14.5			9.1
% Oil		81	%		80	%		70	%
% Proved producing		72	%		67	%		74	%
PV-10 (millions)	$	392.1		$	200.3		$	148.1
Pro forma standardized measure (millions)⁽³⁾	$	255.0		$	132.1		$	108.2

(1)	The December 31, 2005, 2006 and 2007 information excludes the impact of our financial derivative activities.

(2)

(3)

Because each of the Predecessor Companies was a flow-through entity for state and federal tax purposes, our historical standardized measure does not deduct state or federal taxes. In addition, during 2007, the Predecessor Companies were flow-through entities for state and federal tax purposes until the effective time of the Reorganization Transactions in July 2007, when they became taxable entities. Because of the Reorganization Transactions, we show pro forma standardized measure in the table above, which deducts state and federal taxes for each of the periods shown.

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. In evaluating our company, the factors described below should be considered carefully. The occurrence of one or more of these events could significantly and adversely affect our business, prospects, financial condition, results of operations and cash flows.

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:

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.

Enhanced Oil Recovery, or 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 Lawrence Field ASP Flood Project 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 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.

We have limited experience in drilling wells to the Marcellus Shale and less information regarding reserves and decline rates in the Marcellus Shale than in other areas of our Appalachian operations. Wells drilled to the Marcellus Shale will be deeper, more expensive and more susceptible to mechanical problems in drilling and completing than wells in the other areas.

We have limited experience in drilling wells to the Marcellus Shale. As of April 7, 2008, we have drilled two vertical test wells to the Marcellus Shale, which have not yet been completed. Other operators in the Appalachian Basin also have limited experience in drilling wells to the Marcellus Shale. Thus, we have much less information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale than we have in our other areas of operation. In addition, the wells to be drilled in the Marcellus Shale will be drilled deeper than in our other primary areas, which make the Marcellus Shale wells more expensive to drill and complete. The wells will also be more susceptible to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore. In addition, the fracturing of the Marcellus Shale will be more extensive and complicated than fracturing the geological formations in our other areas of operation.

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

New Albany Shale reservoirs are complex, often containing unusual features that are not well understood by drillers and producers. These formations are believed to contain natural fractures. Results of past drilling in these formations 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 acreage is not subject to the level of natural 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 materially adversely affected.

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 have a material adverse impact on our business.

For the year ended December 31, 2007, 76% of our net daily production came from the Illinois Basin area, and, as of December 31, 2007, approximately 75% of our proved reserves were located in the fields that comprise this area. In addition, for the year ended December 31, 2007, approximately 54% of our net daily production came from the Lawrence Field, and, as of December 31, 2007, approximately 53% of our proved reserves were located on this property. Moreover, we plan to allocate approximately 21% of our 2008 capital expenditures to our Lawrence Field ASP Flood Project. 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, 2007, constituted approximately 82% of our total oil and natural gas sales revenue for such period. Our inability to continue to provide services to key customers, if not offset by additional sales to our other 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.

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.

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 in contamination of the areas surrounding Bridgeport and Petrolia, Illinois, with hydrogen sulfide, or H₂S. The complaint, as amended, asserts several causes of action, including violation of the Illinois Environmental Protection Act, violation of the federal Resource Conservation And Recovery 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. The plaintiffs have filed a motion for class certification requesting that the court certify the case as a class action.

We intend to vigorously oppose the plaintiffs’ motion for class certification and the claims that have been asserted by the plaintiffs’ against PennTex Illinois and Rex Operating in this lawsuit. If, however, 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. (For more information regarding the putative class action lawsuit, please see “Business—Legal Proceedings.”)

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, 2007, we incurred realized losses of $6.2 million 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—Recently Adopted Accounting Pronouncements.”

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 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 senior credit facility with KeyBank National Association (“Key Bank”), the percentage of our total production volumes with respect to which we will be allowed to enter into derivative contracts is limited, and we therefore retain the risk of a price decrease for our remaining production volume.

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 cash flows, 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 existing 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 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:

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.

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:

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 with certainty 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 before 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:

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 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:

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 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. Also, our credit facility contains covenants that restricts our ability to, among other things, materially change our business, approve and distribute dividends, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions.

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 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 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, it is not possible to insure fully against pollution and environmental risks.

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:

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 operations depend on the continuing efforts of our executive officers and senior management. 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.

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 to comply with these laws and regulations, which may require:

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

Being a public company has increased our expenses and administrative workload.

We completed our initial public offering in July 2007. As a public company, we must comply with various laws and regulations, including the Sarbanes-Oxley Act of 2002 and related rules of the Securities and Exchange Commission, or the SEC, and requirements of NASDAQ. We were not required to comply with all of these laws and requirements before our initial public offering. Complying with these laws and regulations requires the time

and attention of our board of directors and management and increases our expenses. Among other things, we must:

In addition, being a public company has made it more expensive for us to obtain director and officer liability insurance. In the future, we may be required to accept reduced coverage or incur substantially higher costs to obtain this coverage. These factors could also make it more difficult for us to attract and retain qualified executives and members of our board of directors, particularly directors willing to serve on our audit committee.

Our common stock has only been publicly traded since July 30, 2007 and the price of our common stock has fluctuated substantially since then and may fluctuate substantially in the future.

Our common stock has only been publicly traded since our initial public offering on July 30, 2007. The price of our common stock has fluctuated significantly since then. From July 30, 2007 to April 7, 2008, the trading price of our common stock ranged from a low of $7.50 per share to a high of $17.92 per share. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:

We may fail to meet expectations of our stockholders or of securities analysts at some time in the future, and our stock price could decline as a result.

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. We are 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. 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.

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 beneficially own approximately 52% of the outstanding shares of our common stock as of March 31, 2008 and will collectively beneficially own approximately 35% of the outstanding shares of our common stock after completion of this offering.

Provisions in our certificate of incorporation and bylaws will have the effect of delaying or preventing a change of control or changes in our management. These provisions include the following:

In addition, we are subject the provisions of Section 203 of the Delaware General Corporation Law. These provisions may prohibit large stockholders, in particular those owning 15% or more of our outstanding voting stock, from merging or combining with us.

In addition, Lance T. Shaner, our Chairman, beneficially owns approximately 41%, and our other executive officers collectively own approximately 11%, of the outstanding shares of our common stock. After completion of this offering, Mr. Shaner will beneficially own approximately 26%, and our other executive officers will collectively own approximately 8% of the outstanding shares of our common stock. As a result, these stockholders, acting together, will have the ability to exert substantial influence over all matters requiring approval by our stockholders, including the election and removal of directors, any proposed merger, consolidation or sale of all or substantially all of our assets and other corporate transactions.

These provisions in our certificate of incorporation and bylaws and under Delaware law, and this concentrated ownership of our common stock by our Chairman and executive officers could discourage potential takeover attempts and could reduce the price that investors might be willing to pay for shares of our common stock.

Because we have no plans to pay dividends on our common stock, stockholders must look solely to appreciation of our common stock 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, our senior credit facility limits the payment of dividends without the prior written consent of the lenders. Accordingly, stockholders must look solely to appreciation of our common stock to realize a gain on their investment. This appreciation may not occur.

Some of the information, including all of the estimates and assumptions, contained in this prospectus and the documents we incorporate by reference contain forward-looking statements within the meaning of sections 27A of the Securities Act of 1933, as amended, and 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this prospectus and the documents we incorporate by reference, 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:

Other factors that could cause actual results to differ materially from those anticipated are discussed in our periodic filings with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2007.

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 or the date of the document incorporated by reference, respectively. 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.

We intend to use the net proceeds from this offering to fund, in part, our capital expenditure program for 2008, including our Lawrence Field ASP Project and Marcellus Shale leasing and drilling activities, and for other corporate purposes. Pending those uses, we intend to use a portion of the net proceeds (i) to repay borrowings under our senior credit facility with KeyBank, which as of March 31, 2008 totaled $38.2 million, and (ii) invest our net proceeds from this offering in short-term, investment grade, interest-bearing securities. We will then reborrow amounts from time to time under our senior credit facility as capital expenditures exceed our overnight investments and cash flow from operations in periods subsequent to this offering.

Loans made under our senior credit facility mature on September 28, 2012. At our election, borrowings under the senior credit facility bear interest at a rate per annum equal to:

The average interest rate on our senior credit facility at December 31, 2007 was approximately 6.8%, before the effect of interest rate hedging.

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 $3.8 million, or $4.9 million if the underwriters’ over-allotment option is exercised in full.

Certain affiliates of the underwriters in this offering are lenders under our senior credit facility and may receive a portion of the net proceeds we receive from this offering based on the amount of the loan they have extended under our senior credit facility.

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

The following table sets forth the combined cash and cash equivalents, total debt and owners’ equity as of December 31, 2007 (1) on an actual basis, and (2) on an adjusted basis to reflect the sale of 4,000,000 shares of common stock in this offering, at an assumed offering price of $17.39 per share, after deducting the estimated underwriting discounts and the estimated offering expenses and the application of the estimated net proceeds from this offering as set for under “Use of Proceeds.”

A (1) $1.00 increase in the assumed public offering price of $17.39 per share would increase each of cash and cash equivalents, additional paid-in capital and total owners’ equity by $3.8 million, and (2) a $1.00 decrease in the assumed offering price of $17.39 per share would decrease each of cash and cash equivalents, additional paid-in capital and total owners’ equity by $3.8 million.

You should read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in this prospectus and our consolidated financial statements and related notes as of December 31, 2007 and 2006 and for each of the years ended December 31, 2007, 2006 and 2005, incorporated by reference into this prospectus.

We completed the initial public offering of our common stock on July 30, 2007. Since that time, our common stock has been quoted on the NASDAQ Global Market under the symbol “REXX”. Before then, there was no public market for our common stock. As of April 4, 2008, there were approximately 246 holders of record of our common stock.

The following table sets forth, for the periods indicated, the range of the daily high and low sale prices for our common stock as reported by NASDAQ.

We have not paid cash dividends on our common stock since our inception in March 2007. 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 to finance the expansion of our business. In addition, the terms of our senior credit facility restrict our ability to pay cash dividends to holders of our common stock.

The following table shows selected consolidated and combined financial data of Rex Energy Corporation and the Predecessor Companies for each of the periods indicated. The historical consolidated and combined financial data has been prepared for Rex Energy Corporation as of and for the year ended December 31, 2007. The historical combined financial data has been prepared for the Predecessor Companies as of and for the years ended December 31, 2006, 2005, 2004, and 2003. The historical consolidated and combined financial statements as of and for the years ended December 31, 2007, 2006, 2005 and 2004 are derived from the historical audited financial data of Rex Energy Corporation and the Predecessor Companies. The historical combined financial statements as of and for the year ended December 31, 2003 are derived from the historical unaudited financial data of the Predecessor Companies. All material intercompany balances and transactions have been eliminated. Because each of the Predecessor 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 for the years ended December 31, 2006, 2005, 2004, and 2003 and the seven month period ended July 31, 2007. Provision for income tax is presented for the five month period ended December 31, 2007. This information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this prospectus and our consolidated and combined financial statements and related notes as of December 31, 2007 and 2006 and for each of the years ended December 31, 2007, 2006 and 2005, incorporated by reference into this prospectus. These selected combined historical financial results may not be indicative of our future financial or operating results.

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” 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, to analyze such things as:

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, nor 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 we believe this measure is 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 it is important to consider both net income determined under GAAP and EBITDAX to evaluate our performance.

The following table presents a reconciliation of our net income to our EBITDAX for each of the periods presented ($ in thousands):

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 cash flows before income tax of our estimated proved reserves. Our estimated future cash flows as of December 31, 2005, 2006 and 2007 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, 2005, 2006 and 2007, without escalation, using $57.75, $57.75 and $92.50 per Bbl of oil, respectively, and $10.08, $5.635 and $6.795 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.

We show pro forma standardized measure because each of the Predecessor Companies was a flow-through entity for federal and state tax purposes and thus our historical standardized measure of discounted future net cash flows did not deduct federal and state taxes for each of the years ended December 31, 2005 and 2006 and for a portion of the year ended December 31, 2007. The pro forma standardized measure of discounted future net cash flows shown in the table above deducts state and federal taxes for each of the periods shown.

Prior to our initial public offering and the Reorganization Transactions, which closed on July 30, 2007, we conducted our operations through several operating partnerships and companies, which we refer to as the Predecessor Companies, under the common control of Lance T. Shaner, our Chairman. Pursuant to the Reorganization Transactions, we combined the operations of these partnerships and companies under a holding company structure and the equity interests the Predecessor Companies were exchanged for shares of our common stock. Rex Energy Corporation serves as the parent holding company for this structure.

Because the Company is succeeding to the businesses of each of the Predecessor Companies, we designated the Predecessor Companies on a combined basis as our accounting predecessor. As such, incorporated by reference into this prospectus are the annual audited combined financial statements of the Predecessor Companies as of and for the years ended December 31, 2006 and 2005. In addition, the audited consolidated and combined financial statements of Rex Energy Corporation for the year ended December 31, 2007, incorporated by reference into this prospectus, reflect the combined financial statements of the Predecessor Companies for the period from January 1, 2007 through July 30, 2007.

The following discussion and analysis should be read in conjunction with the “Selected Historical Financial and Operating Data” included in this prospectus and the consolidated and combined financial statements and related notes incorporated by reference into 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.

We are an independent oil and gas company operating in the Illinois Basin, Appalachian Basin and the Southwestern Region of the United States. We have pursued 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 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.

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 ($ in thousands):

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 the 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.

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. The following table presents these metrics for each of the three years ended December 31, 2007, 2006 and 2005.

Production costs 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 production costs 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 decrease on a per unit basis. Our production costs per BOE produced in 2007 was $24.28 as compared to $19.72 in 2006 and $20.70 in 2005.

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 2005, from 9.1 MMBOE at year end 2005 to 14.5 MMBOE at year end 2006 to 15.9 MMBOE at year end 2007. 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 5.4 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 707 MBOE. Our reserve replacement ratio for year end 2007 was approximately 139% based on an increase in total proven reserves of 1.4 MMBOE, total production for the year of 1.0 MMBOE, purchases of reserves of 84 MBOE, extensions discoveries and other additions of 342 MBOE, and revisions of previous estimates of 2.0 MMBOE.

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 2007 to 14.9% from 15.7% in 2006 and from 17.3% in 2005. Although we anticipate our general and administrative expenses will increase over the next two years as a result of additional administrative expenses associated with 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.

Operating revenue increased 45.8% for 2007 over 2006. This increase is primarily due to higher production with higher average sales prices per BOE, partially offset by increased realized losses on derivative activity. For 2007, production increased 30.5% from 2006 to 1,008,190 BOE compared to 772,386 BOE in 2006 due to the continued success of our drilling programs and our acquisitions. Realized losses on derivative activities increased by 39.7% to $6.2 million for 2007 as compared to $4.4 million for 2006.

Operating expenses increased $23.0 million in 2007, or 70.3%, as compared to 2006. Operating expenses are primarily composed of production expenses, general and administrative expenses, exploration expenses, and depreciation, depletion, amortization, and accretion expenses. These increases were due, in part, to acquisitions consummated in the final six months of 2006 within the Illinois basin whereby we acquired all of the oil producing assets owned by Tsar Energy II, L.L.C. and certain oil producing assets owned by Team Energy, L.L.C. and its affiliates. The increase is also partially attributed to approximately $2.1 million of increased depreciation, depletion and amortization expenses realized over the five-month period ended December 31, 2007 resulting from a step-up in book basis of assets caused by the acquisition of all minority interests from the Predecessor Companies.

Comparison of the Year Ended December 31, 2007 to the Year Ended December 31, 2006

Oil and gas revenue for the years ended December 31, 2007 and 2006 ($ in thousands except price per BOE) is summarized in the following table:

Average realized price received for oil and gas during 2007 was $56.86 per BOE, an increase of 12.2%, or $6.16 per BOE, from the prior year. The average realized price for oil in 2007 increased 15.5% or $8.01 per barrel, whereas the average realized price for natural gas decreased 5.8%, or $0.46 per Mcf, from 2006. Our derivative activities effectively decreased net realized prices by $6.15 per BOE in 2007 and $5.74 per BOE in 2006.

Production volumes increased 30.5% from 2006 primarily due to acquisitions in the Illinois Basin and continued success with our oil and gas well drilling activities. Our production for 2007 averaged approximately 2,762 BOE per day of which 76.4% was attributable to the Illinois basin, 13.0% to the Appalachian basin, and 10.6% to activities in the Southwestern Region.

Other operating revenue for 2007 of approximately $452,000 decreased $18,000, or 3.8%, from 2006. We generate other operating revenue from various activities such as revenue from the transportation of natural gas and disposal of salt water from non-related parties through a salt water disposal facility we own and operate for our own oil and gas production activities in the Southwestern Region.

Production and lease operating expenses increased approximately $9.2 million, or 60.7%, in 2007 from 2006. These expenses typically increase as we add new wells and make certain improvements to existing wells in production. These increases were principally due to acquisitions consummated in the final six months of 2006 within the Illinois basin from Tsar Energy II, L.L.C. and Team Energy, L.L.C. and its affiliates.

General and administrative expenses of approximately $8.6 million for 2007 increased approximately $2.4 million, or 38.2%, from 2006. This increase was primarily as a result of oil and gas property acquisitions in the Illinois basin during the final six months of 2006 which resulted in reduced overhead income on wells that we operated for Tsar Energy II, L.L.C. This overhead income had offset general and administrative expenses. In October of 2006, we acquired all of the interests of Tsar Energy II, L.L.C. in these wells at which time we ceased to recognize the overhead income associated with these wells. Additionally, with the completion of our initial public offering in July 2007, we have recognized increases to salary and benefit expenses associated with increased staffing levels.

DD&A expenses of approximately $19.6 million for 2007 increased approximately $8.4 million, or 74.8%, from 2006. This increase was partially due to an increase in production volumes resulting from the Tsar Energy II, L.L.C. and Team Energy, L.L.C. acquisitions in the Illinois basin. The increase is also partially attributed to

approximately $2.1 million of increased depletion and amortization expenses realized over the five month period ending December 31, 2007 resulting from a step-up in book basis of assets caused by the acquisition of minority interests from the Predecessor Companies.

Interest expense, net of interest income for 2007 was approximately $5.6 million as compared to $6.0 million for 2006. The decrease of $385,000 is primarily due to the decrease in the average balance on our long-term debt, lines of credit, and other loans and notes payable which have been significantly reduced with the proceeds of our initial public offering, which closed July 30, 2007.

Gain on sale of oil and gas properties for 2007 was approximately $185,000 as compared to $91,000 for 2006. We, from time to time, sell or otherwise dispose of certain fixed assets and wells that are no longer effectively used by us and a gain or loss may be recognized when such an asset is sold.

Unrealized loss on oil and gas derivatives for 2007 was approximately $26.3 million as compared to a gain of $5.0 million for 2006. These changes are attributed to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Unrealized losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the time we entered into a derivative contract while unrealized gains would suggest the opposite. Our derivative program is designed to provide us with a greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.

Other income (expense) increased by 230% to approximately $171,000 of income for 2007 from approximately $132,000 of expense for 2006. The change year over year is primarily due to the recognition of gains on the sale of scrap inventory.

Net loss before minority interests for 2007 was approximately $29.4 million, a decrease of approximately $35.3 million from net income of approximately $5.9 million for 2006 as a result of the factors discussed above.

Comparison of the Year Ended December 31, 2006 to the Year Ended December 31, 2005

Oil and gas revenue for the years ended December 31, 2006 and 2005 ($ in thousands except price per BOE) is summarized in the following table:

Average realized price received for oil and gas during 2006 was $50.70 per BOE, an increase of 33.0%, or $12.59 per BOE, from the prior year. The average realized price for oil in 2006 increased 14.9% or $6.73 per barrel, whereas the average realized price for natural gas increased 96.2%, or $3.87 per Mcf, from 2005. Our derivative activities effectively decreased net realized prices by $5.74 per BOE in 2006 and $14.00 per BOE in 2005.

Production volumes increased 36.4% for the year ended December 31, 2006, as compared to the same period in 2005, primarily due to acquisitions in the Illinois Basin and continued success with our oil and gas well drilling activities. Our production for the year averaged approximately 2,116 BOE per day of which 70.7% was attributable to the Illinois basin, 14.0% to the Appalachian basin, and 15.3% to activities in the Southwestern Region.

Other operating revenue for the year ended December 31, 2006 increased $200,000 to $470,000 from $270,000 for the same period in 2005. We generate other operating revenue from various activities such as revenue from the transportation of natural gas and disposal of salt water from non-related parties through a salt water disposal facility we own and operate for our own oil and gas production activities in the Southwestern Region.

Production and lease operating increased approximately $3.5 million, or 30.0%, in 2006 from 2005. These expenses typically increase as we add new wells and make certain improvements to existing wells in production. These increases were principally due to acquisitions consummated in the final six months of 2006 within the Illinois basin from Tsar Energy II, L.L.C. and Team Energy, L.L.C. and its affiliates.

General and administrative expenses 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 U.S. EPA enforcement matter and the putative class action lawsuit, 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 before 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.

Depreciation, depletion, amortization, and accretion (“DD&A”) expenses for the year ended December 31, 2006 increased approximately $7.9 million, or 238%, from $3.3 million for the same period in 2005. This increase was partially due to an increase in production volumes and depletable assets resulting from the Tsar Energy II, L.L.C. and Team Energy, L.L.C. acquisitions in the Illinois basin during 2006.

Interest expense, net of interest income for the year ended December 31, 2006 was approximately $6.0 million as compared to $1.3 million for the same period in 2005. The increase of $4.8 million resulted from increased borrowings associated with our 2006 acquisitions.

Gain on sale of oil and gas properties for the year ended December 31, 2006 was approximately $91,000 as compared to $1.0 million for the same period in 2005. We, from time to time, sell or otherwise dispose of certain fixed assets and wells that are no longer effectively used by us and a gain or loss may be recognized when such an asset is sold.

Unrealized loss on oil and gas derivatives includes a gain of approximately $5.0 million for the year ended December 31, 2006 as compared to a loss of $5.5 million for the same period in 2005. These changes are attributed to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Unrealized losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the time we entered into a derivative contract while unrealized gains would suggest the opposite. Our derivative program is designed to provide us with a greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.

Other income (expense) decreased by $348,000 to an expense of $132,000 for the year ended December 31, 2006 as compared to income of $216,000 for the same period in 2005. The change was due to expenses related to property damage at one of our facilities in 2006.

Net income (loss) 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 as a result of the factors described above.

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 facility. The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties. We borrow funds on the senior credit facility as needed to supplement our operating cash flow and 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 have been primarily used to fund exploration and development of our oil and gas interests.

Financial Condition and Cash Flows for the Years Ended December 31, 2007, 2006 and 2005

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

Net cash provided by operating activities increased by approximately $4.6 million in 2007 when compared to 2006, to $17.6 million. In 2007, cash flows increased primarily due to increases in production, which were a result of acquisitions in the Illinois Basin during the final six months of 2006 and continued success with our oil and gas well drilling activities, and higher realized prices. These increases in cash were partially offset by increases in operating expenses, which were also primarily due to the acquisitions in the Illinois Basin that took place in the second half of 2006.

Net cash used in investing activities decreased by approximately $54.3 million in 2007 when compared to 2006, to $40.1 million. In 2007, cash used decreased primarily as a result of the acquisitions in the Illinois Basin during 2006. This decrease was partially offset by increased expenditures in 2007 for the development of oil and gas properties as part of the 2007 drilling and recompletion program and an increase in the proceeds received on the sale of oil and gas properties, prospects, and other assets.

Net cash provided by financing activities decreased by approximately $56.4 million in 2007 when compared to 2006, to $23.0 million. In 2007, cash flows provided by financing decreased primarily due to the combination of increased borrowings in 2006 to fund the acquisitions that took place in the Illinois Basin and the

large repayment of debt in 2007 with the proceeds of our initial public offering. Also contributing to the decrease in cash flows during 2007 were increased repayments of participation liability and a decrease in the net capital contributions from the Partners of the Predecessor Companies. These decreases in cash flow were partially offset by a decrease in payments to related parties.

On September 28, 2007, we entered into a credit agreement with KeyBank, as Administrative Agent, BNP Paribas, as Syndication Agent, Sovereign Bank, as Documentation Agent, and lenders from time to time parties thereto, which we refer to in this prospectus as our senior credit facility. Borrowings under our senior credit facility are limited by a borrowing base that is determined in regard to our oil and gas properties. The borrowing base is $75 million; however, our senior credit facility provides that the borrowing base may be increased up to $200 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed in the agreement. Within that borrowing base, outstanding letters of credit are permitted up to $10 million. Loans made under our senior credit facility mature on September 28, 2012, and in certain circumstances, we will be required to prepay the loans. At our election, borrowings under our senior credit facility bear interest at a rate per annum equal to (a) the London Interbank Offered Rate for one, two, three, six or nine months (“Adjusted Libor Rate”) plus an applicable margin ranging from 100 to 175 basis points plus a commitment fee ranging from 25 to 37.5 basis points or (b) the higher of KeyBank’s announced prime rate (“Prime Rate”) and the federal funds effective rate from time to time plus 0.5%, in each case, plus an applicable margin ranging from 0 to 25 basis points plus a commitment fee ranging from 25 to 37.5 basis points. Interest is payable on the last day of each relevant interest period in the case of loans bearing interest at the Adjusted Libor Rate and quarterly in the case of loans bearing interest at the Prime Rate. The average interest rate on our senior credit facility at December 31, 2007 was approximately 6.8%, before the effect of interest rate hedging. The lenders are required to re-determine the borrowing base semi-annually, in good faith, based on, among other things, reports regarding our oil and gas reserves attributable to our oil and gas properties, together with a projection of related production and future net income, taxes, operating expenses and capital expenditures. On or before March 1 and September 1 of each year, we must furnish to the lenders a reserve report evaluating our oil and gas properties as of the immediately preceding January 1 and July 1. The reserve report as of January 1 of each year must be prepared by one or more independent petroleum engineers approved by Key Bank. Any re-determined borrowing base will become effective on the subsequent April 1 and October 1. We may, or Key Bank at the direction of a majority of the lenders may, each elect once per calendar year to cause the borrowing base to be re-determined between the scheduled re-determinations. In addition, we may request interim borrowing base re-determinations upon our proposed acquisition of proved developed producing oil and gas reserves with a purchase price for such reserves greater than 10% of the then borrowing base. We provided the lenders with the reserve report of Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm, with respect to our proved reserves as of December 31, 2007.

Our senior credit facility contains covenants that restricts our ability to, among other things, materially change our business, approve and distribute dividends, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions. Our senior credit facility also requires we meet, on a quarterly basis, minimum financial requirements of consolidated current ratio, EBITDAX to interest expense and total debt to EBITDAX. As of December 31, 2007, we were in compliance with these ratios. Proceeds of the initial borrowing under our senior credit facility were used to repay, in full, and terminate the existing credit agreement of Rex Energy IV, LLC, our wholly owned subsidiary. Subsequent borrowings under our senior credit facility have been used to finance our working capital needs, and for general corporate purposes in the ordinary course of business, including the exploration, acquisition and development of oil and gas properties. Obligations under our senior credit facility are secured by mortgages on the oil and gas properties of our subsidiaries located in the states of Illinois and Indiana. We are required to maintain liens covering our oil and gas properties representing at least 80% of our total value of all oil and gas properties.

At December 31, 2007, we had a balance of approximately $27.2 million on our senior credit facility and had approximately $47.8 million available for future borrowings.

Our primary needs for cash are for exploration, development and acquisition of oil and gas properties and repayment of principal and interest on outstanding debt. During 2007, $40.4 million of capital was expended on drilling projects, facilities and related equipment and acquisitions to purchase additional interests in producing properties and unproved acreage. The capital program was funded by net cash flow from operations and proceeds from borrowings. The 2008 capital budget of $138.7 million is expected to be funded primarily by proceeds from this offering, cash flow from operations and proceeds from borrowings. To the extent capital requirements exceed proceeds from this offering, internal cash flow and proceeds from asset sales, debt or additional equity may be issued to fund these requirements. We currently believe we have sufficient liquidity and cash flow to meet our obligations; however, a drop in oil and gas prices or a reduction in production or reserves could adversely affect our ability to fund capital expenditures and meet our financial obligations. Also, our obligations may change due to acquisitions, divestitures and continued growth. In addition to this offering, we may issue additional shares of stock, subordinated notes or other debt securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.

Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that we are required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on us.

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 consolidated financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future cash flows, asset retirement obligations, impairment (when applicable) of undeveloped properties, the collectability 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. These 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 our ability to generate future income. Future changes in these assumptions may materially affect these significant estimates in the near term.

Our 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, 2005, our independent engineering firm, Netherland, Sewell, and Associates, Inc., prepared a reserve and economic evaluation of each of the Predecessor Companies’ proved oil and gas reserves which has been combined by us to determine our total proved oil and gas reserves for the period. For the years ended December 31, 2006 and 2007,

Netherland Sewell and Associates, Inc. prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. Our independent engineering firm adheres to the same guidelines when preparing their reserve reports. The accuracy of our 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. The independent reserve engineer estimates reserves annually on December 31. This annual estimate results in a new DD&A rate which we use for the preceding fourth quarter after adjusting for fourth quarter production.

We use put and call options (collars) and fixed rate swap contracts to manage price risks in connection with the sale of oil and natural gas. We also use interest-rate swap agreements to manage interest-rate risks associated with our variable-rate credit facility. We account for these collar and swap contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS No. 133”).

We have established the fair value of all derivative instruments using estimates determined by our counterparties. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. The values we report in our 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. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil and natural gas production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings.

We account for 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. We periodically review our estimated proved reserve estimates and makes changes as needed to depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our 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 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.

We account 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 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. At December 31, 2007 oil and gas properties valued at $642,000 were impaired and included in depreciation, depletion, and amortization on the consolidated and combined statement of operations for the year ended December 31, 2007. The impairment expense represents 100% of the carrying value of those assets associated with a coalmine methane project in West Virginia for which we can no longer identify a suitable market for the methane gas produced by the mine.

Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.

Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized.

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.

In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), no amortization is recorded for goodwill or intangible assets deemed to have indefinite lives for acquisitions completed after June 30, 2001. SFAS No. 142 requires that goodwill and non-amortizable assets be assessed annually for impairment. At December 31, 2007, our intangible assets consist of $32.7 million of goodwill and $1.3 million of

intangible assets comprised of sales agreements that are amortized over an estimated useful life of five years. For the years ended December 31, 2007, 2006, and 2005, we recorded amortization expense of $111,000, $0 and $0, respectively. Amortization expenses were recorded only for those periods following the Reorganization Transactions. We are in the early stages of gathering data and performing an analysis and evaluation of the assets and liabilities assumed as of the date of acquisition. We have preliminarily estimated the excess cost over the fair values of those assets and liabilities. To the extent that the estimates used in the preliminary purchase price allocation need to be adjusted, we will do so upon making that determination, but not later than one year from the date of acquisition.

Goodwill and identified intangible assets that have an indefinite useful life are subject to impairment testing, which we conduct annually, or on an interim basis if events or changes in circumstances between annual tests indicate the assets might be impaired. We perform our annual impairment test for goodwill and identified intangible assets that have an indefinite useful life as of December 31 of each year. The impairment test involves a comparison of the fair value of each tangible and intangible asset to its carrying value. If the fair value is less than the carrying value, a further test is required to measure the amount of impairment.

We account 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 future abandonment cost is capitalized as part of the carrying amount of our 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.

We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed many months after the close of a calendar year, tax returns are subject to audit which can take years to complete and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carry forwards and other deductible differences. We routinely evaluate deferred tax assets to determine the likelihood of realization. A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are not likely to be realized.

We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.

A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. We have recognized an accrued liability of approximately $384,000 at December 31, 2007 for the estimated cost of pending litigation matters.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measure at fair value. It requires that unrealized gains and losses on items for which the fair value option has been elected be recorded in net income. The statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. For us, SFAS No. 159 will be effective January 1, 2008, and retrospective application is not permitted. Should we elect to apply the fair value option to any eligible items that exist at January 1, 2008, the effect of the first re-measurement to fair value would be reported as a cumulative effect adjustment to the opening balance of retained earnings. We will adopt SFAS No. 159 as of January 1, 2008 and do not expect the adoption will have a material impact on our financial statements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurement.” This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but may require some entities to change their measurement practices. For us, SFAS No. 157 will be effective January 1, 2008. We have not yet determined whether SFAS No. 157 will have a material impact on our financial condition, results of operations or cash flow. However, we believe we will be required to provide additional disclosures as part of future financial statements, beginning with the first quarter of 2008.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) replaces SFAS No. 141. The statement retains the purchase method of accounting for acquisitions, but requires a number of changes, including changes in the way assets and liabilities are recognized in the purchase accounting. It changes the recognition of assets acquired and liabilities assumed arising from contingencies, requires the capitalization of in-process research and development at fair value, and requires the expensing of acquisition-related costs as incurred. The statement will apply prospectively to business combinations occurring in our fiscal year beginning January 1, 2009. We are currently evaluating provisions of this statement.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”), which provides direction on reporting minority (noncontrolling) interests in the consolidated financial statements. The standards set forth in SFAS No. 160 include clearly identifying and labeling noncontrolling interests in the consolidated statement of equity, separate from the parent’s equity; clearly identifying consolidated net income of the parent and the noncontrolling interests on the consolidated statement of income; consistently accounting for changes in the parent ownership interest when the parent preserves its controlling interest; any retained noncontrolling equity investment of a deconsolidated subsidiary and any resulting gain or loss will be measured using fair value and; disclosures must provide a level of detail that clearly identifies and separates the interests of the parent and the interest of the noncontrolling owners. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. We are currently evaluating the effect that the implementation of SFAS 160 will have on our results of operations and financial condition, but do not expect it will have a material impact.

Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.

We account for our natural gas and oil exploration and production activities under the successful efforts method of accounting. See Note 2 to our consolidated and combined financial statements—“Summary of Significant Accounting Policies.”

To mitigate some of our commodity price risk, we engage periodically in certain other limited derivative activities including price swaps and costless collars to establish some price floor protection.

For the twelve month periods ended December 31, 2007 and 2006, the net realized loss on oil and natural gas derivatives was approximately $6.2 million and $4.4 million, respectively. The losses are reported as net realized loss on derivatives in the Consolidated and Combined Statements of Operations.

For the twelve month period ended December 31, 2007, the net unrealized loss on oil and natural gas derivatives was approximately $26.3 million as compared to a net unrealized gain of approximately $5.0 million on oil and natural gas derivatives for 2006. The net unrealized gains and losses are reported as net unrealized gains (losses) on derivatives in the Consolidated and Combined Statements of Operations.

While the use of derivative arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of natural gas and oil. We enter into the majority of our derivatives transactions with two counterparties and have a netting agreement in place with each of these counterparties. We do not obtain collateral to support the agreements but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have additional risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the derivative transaction. Moreover, our derivatives arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivatives will vary from time to time.

For a summary of our current oil and natural gas derivative positions at December 31, 2007 refer to Note 9 to our consolidated and combined financial statements, “Fair Value of Financial Instruments and Derivative”.

In addition to our capital expenditure program, we are committed to making cash payments in the future on two types of contracts: note agreements and operating leases. As of December 31, 2007, we do not have any capital leases nor have we entered into any material long-term contracts for equipment. As of December 31, 2007, we do not have any off-balance sheet debt or other such unrecorded obligations and we have not guaranteed the debt of any other party. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2007. In addition to the contractual obligations listed on the table below, our balance sheet at December 31, 2007 reflects accrued interest payable on our bank debt of $114,566 which is payable in January 2008.

The following summarizes our contractual financial obligations at December 31, 2007 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities.

At March 31, 2008, we had $38.2 million of debt outstanding. Of this amount, $20.0 million bears interest at fixed rates of 5.15% after the effect of interest rate hedging. The remaining balance of approximately $18.2 million bears interest at floating rates, which averaged 4.4% at March 31, 2008. The 30-day LIBOR rate on March 31, 2008 was 2.7%.

We do not currently use any off-balance sheet arrangements to enhance our liquidity or capital resource position, or for any other purpose.

We are exposed to various risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decline significantly, revenues and cash flow would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. We have designed our hedging policy to reduce the risk of price volatility for our production in the natural gas and crude oil markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we use include swaps and collars. The volume of derivative instruments that we may use is governed by the risk management policy and can vary from year to year, but under most circumstances will apply to only a portion of our current and anticipated production and provide only partial price protection against declines in oil and natural gas prices. We are exposed to market risk on our open contracts, to the extent of changes in market prices of oil and natural gas. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges.

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and prime rate, as determined by our lenders, based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

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

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

For a more detailed discussion of our derivative activities, see the information see the information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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:

Develop Our Existing Properties: Our focus is to develop our asset base in each of our operating basins including:

Maintain Flexibility: Because of the volatility of commodity prices and the risks involved in our industry, we believe in remaining flexible in our capital budgeting process. When appropriate, we may defer capital projects to seize an attractive acquisition opportunity or reallocate capital towards projects where we believe we can generate higher than anticipated returns. We also believe in maintaining a strong balance sheet and using commodity hedging. This allows us to be more opportunistic in lower price environments as well as providing more consistent financial results.

The following table sets forth information regarding oil and gas production and revenues for the last three years ($ in thousands):

We market nearly all of our oil and gas production from the properties we operate for both our interest and that of the other working interest owners and royalty owners.

In the Illinois Basin, we store the oil produced at 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 refinery facilities. The revenue we derived from our sales to Countrymark Cooperative, LLP for the year ended December 31, 2007 constituted approximately 82% of our oil and natural gas sales 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 purchasers to meet their obligations or the loss of our market 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. (“Marathon”) 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 Southwestern Region, 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, among other things, 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. Demand for oil has increased due to increased industrialization in many parts of the world. Nonetheless, because 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.

We enter into derivative transactions with unaffiliated third parties to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and gas prices. For a more detailed discussion, see the information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The table below summarizes certain data for our core operating areas for the year ended December 31, 2007:

Segment reporting is not applicable to us as we have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis.

Total proved reserves increased approximately 1.2 MMBOE, or 11%, to approximately 12.0 MMBOE at December 31, 2007, when compared to year-end 2006. Annual production increased 41% over 2006. Capital expenditures in 2007 for developmental drilling and facility improvements in the region were approximately $14.8 million, which funded the drilling of 32 gross (31.8 net) development wells, of which 23 gross (22.9 net)

were productive and 9 gross (8.9 net) were expected to be completed and producing during the first quarter of 2008. Capital expenditures in 2007 also funded the recompletion of 12 gross (11.9 net) recompletions. Additionally, in the Illinois Basin, capital expenditures for drilling and facilities development for the New Albany Shale project totaled approximately $3.2 million, which funded the drilling of 8 gross (2 net) exploratory wells. These wells are currently under evaluation to determine if they will be economical to produce. Capital expenditures for drilling and facilities development for the Lawrence Field ASP Flood Project in Lawrence County, Illinois totaled approximately $4.5 million, of which approximately $3.1 million funded facilities development and the remaining $1.4 million funded the drilling or recompletion of 10 gross (10 net) exploratory producer wells and 7 gross (7 net) exploratory injector wells.

At December 31, 2007, the Illinois Basin had a development inventory of 216 proven drilling locations and 172 proven recompletions. Development projects include recompletions, infill drilling and continued refinement of secondary recovery operations. These activities also include increasing reserves and production through aggressive cost control, upgrading lifting equipment, improving gathering systems and surface facilities and performing restimulations and refracturing operations.

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

The Lawrence Field is believed to have produced more than 400 million barrels of oil from 23 separate horizons since its discovery in 1906. To date, approximately 40% of the estimated one billion barrels of original oil-in-place has been produced. 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.

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, 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 21% 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 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. While we believe the results of this project are pertinent, there can be no assurance that our Lawrence Field ASP Flood Project, which uses technology that was not developed at the time of the Robins Lease flood, will achieve similar results.

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 by other companies in several fields around the world resulting in significant incremental recoveries of the original oil-in-place. Chemicals used in the Lawrence Field ASP Flood Project 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 use 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. 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 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 were sent to Surtek for ASP chemical system design. During 2007, Surtek completed their linear and radial core flood analysis on the Cypress and Bridgeport sandstones, which in the laboratory, resulted in an oil recovery rate as high as 21% of the estimated original oil-in-place in the Cypress sandstone, and 24% of the original oil-in-place in the Bridgeport sandstone. These results were in line with our initial projections.

As of April 7, 2008, we controlled, over 306,000 gross (92,000 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.

uneconomical and were expensed as dry holes in the fourth quarter of 2007, two have been tested and are awaiting pipeline connections, and six are still being evaluated to determine whether they will be economical to complete and produce and to design stimulation procedures, if required.

Proven reserves at December 31, 2007 increased 2.4 Bcf, or 24%, from 2006 due primarily to drilling additions which were partially offset by a net unfavorable reserve revision and production. Annual production increased 11% over 2006. Capital expenditures in 2007 for drilling and facility development in the region were approximately $5.2 million, which funded the drilling of 24 gross (14 net) development wells, of which 21 gross (12 net) were productive and three gross (two net) were completed and producing during the first quarter of 2008. During 2007, the region achieved a 100% drilling success rate.

A large portion of our property in Pennsylvania is located in areas where active exploration for the Marcellus Shale, by companies such as Range Resources Corporation (NYSE:RRC), Equitable Resources, Inc. (NYSE:EQT), EOG Resources, Inc. (NYSE:EOG) and Atlas Energy Resources, LLC (NYSE: ATN), is 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 75 to 150 feet on our acreage in southwestern and central Pennsylvania. As of December 31, 2007 we had interests in approximately 44,000 gross (21,000 net) Marcellus Shale prospective acres in these areas of Pennsylvania, and we continue to expand our position. As of April 7, 2008, we increased our position to approximately 64,000 gross (36,000 net) Marcellus Shale prospective acres in these areas of Pennsylvania. During 2008, we plan to begin testing our acreage in these areas and to continue to expand our acreage positions in this emerging play. As of December 31, 2007, we had not yet completed any wells and have not booked any proved reserves in the Marcellus Shale.

Proven reserves decreased approximately 200 MBOE, or 10%, in 2007 compared to 2006. On an annual basis, production decreased approximately 1% from 2006. Capital expenditures in 2007 for drilling and facility development in the region totaled approximately $4.0 million, which funded the drilling of one gross (.8 net) development wells, and three gross (three net) exploratory wells, of which, one gross (one net) was expensed as a dry hole in 2007, one gross (one net) is expected to be expensed as a dry hole in the first quarter of 2008 and one gross (one net) is still being evaluated to determine if it would be economical to produce. Capital expenditures in 2007 also funded the recompletion of 11 gross (8.8 net) wells. At April 7, 2008, the Southwestern Region had a development inventory of eight proven drilling locations and three proven recompletions.

The following table sets forth our estimated proved reserves at the end of each of the past three years:

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 natural gas wells as of December 31, 2007:

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 before 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:

The following table summarizes drilling activity for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. All of our drilling activities are conducted on a contract basis by independent drilling contractors. We own six workover rigs which are used in our Illinois Basin operations. We do not own any drilling equipment.

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often minimal investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:

As of December 31, 2007, we had entered into an interest rate swap derivative instrument in which we effectively hedged our interest rate risk associated with changes in LIBOR on $20,000,000 of notional value. We use the interest rate swap agreement to manage the risk that interest payments on amounts outstanding under the variable rate bank credit facility may be adversely affected by volatility in market interest rates. Under our interest rate swap agreement, we agree to pay an amount equal to a specified fixed rate of interest times a notional principal amount and to receive in return a specified variable rate of interest times the same notional principal amount. At December 31, 2007, we had interest rate swap agreements at an average fixed rate of 5.15% totaling $20.0 million which expire in November 2010. The fair value of the swap at December 31, 2007, was a liability of $207,000 based on current LIBOR quotes. On December 31, 2007, the 30-day LIBOR rate was 4.6%. The critical terms of this interest rate swap and our credit facility closely coincide and there was no ineffectiveness at December 31, 2007. The swap is considered to be a highly effective hedge against future changes in interest rates. We have accounted for the hedge in accordance with SFAS No. 133 by recording the $207,000 unrealized loss at December 31, 2007, on an after tax basis as a decrease to other comprehensive income of $123,000 and an increase in deferred tax assets of $84,000 on our consolidated balance sheet.

Rex Energy Operating Corp. As of the date of this prospectus, Rex Operating Corp. owns our entire administrative and clerical infrastructure and also 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 as well as 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 as well as 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 as well as the El Nora field in Indiana.

R.E. Gas Development, LLC. As of the date of this prospectus, R.E. Gas Development, LLC owns undeveloped oil and gas leasehold interests in Pennsylvania.

Rex Energy I, LLC. As of the date of this prospectus, Rex Energy I, LLC owns producing and non-producing oil and gas assets located in Pennsylvania, Illinois, Indiana, Texas and New Mexico, including minority ownership positions in the Lawrence Field and the majority of our New Albany Shale acreage.

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 of our regions is difficult. Additionally, it is difficult to attract and retain employees, particularly those with expertise in high demand areas.

Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, some states in which we 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. In addition, states in which we operate may 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 or 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:

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, some 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 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. 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 unable to predict 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.

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:

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 “—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, as amended, 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, as amended, or CERCLA, and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons 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 the release of hazardous substances or other pollutants 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 disposed of or 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. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.

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 Clean Water Act 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.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. For instance, 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 climate change-related legislation to restrict greenhouse gas emissions. One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the Lieberman—Warner Climate Security Act or S. 2191, would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. A vote on this bill by the full Senate is expected to occur before mid-year 2008. For example, 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 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. The EPA has indicated that it will issue a rulemaking notice to address greenhouse gas emissions from vehicles and automobile fuels, although the date for the issuance of this notice has not been finalized. The Court’s holding in Massachusetts that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. 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 United States, 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 decreasing our profitability.

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.

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 producing 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 with 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 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 them 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 parties 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 before any final approval.

On April 4, 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. 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.

As of December 31, 2007, we have substantially met all requirements of the consent decree. In a letter dated February 8, 2008, the U.S. EPA, in consultation with the Illinois EPA, approved our proposed plan and schedule for implementing our H₂S control measures in the Lawrence Field. We will be installing these additional controls throughout 2008, with an expected completion date of December 31, 2008.

PennTex Illinois and Rex Operating—H₂S Putative 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 was amended in March 2007 to add a claim for alleged violation of Section 7002(a)(1) of the Resource Conservation And Recovery Act. 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. PennTex Illinois and Rex Operating have filed a joint answer to the amended complaint denying virtually all of the allegations in the amended 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 original order provided for an August 2007 deadline for the completion of pre-certification discovery and the filing of the last brief on class certification issues; however, in August 2007, and again in October 2007, the scheduling and discovery order was amended to extend these deadlines to January 2008.

The plaintiffs filed an amended motion for class certification on January 22, 2008. PennTex Illinois and Rex Operating filed a joint motion opposing class certification on February 22, 2008 and the plaintiffs filed a reply brief on March 20, 2008. The current scheduling and discovery order issued by the court provides that the court may schedule a hearing on class certification if it deems that one is necessary.

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. In addition, we have deposed each of the named plaintiffs and each of plaintiffs’ expert witnesses offered in support of plaintiffs’ motion for class certification. The plaintiffs did not elect to depose our expert witnesses offered in support of our opposition to class certification. The final pretrial conference for this case is scheduled 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.

We believe that there is no evidence that any H₂S 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 is in its initial stages regarding the issue of class certification, 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.

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.

As of December 31, 2007, we had 115 full-time employees, 83 of whom were field personnel. No employees are covered by a labor union or other collective bargaining arrangement. We believe that our relations with our employees are good. We regularly utilize independent consultants and contractors to perform various professional services, particularly in the areas of drilling, completion, field services and on-site production operation services.

The following table sets forth the name, age and position of our directors and executive officers as of March 31, 2008.

Lance T. Shaner has been Chairman and a director of the Company since March 2007. Mr. Shaner founded our wholly owned subsidiary, PennTex Resources, L.P., in 1996, and co-founded and served as an officer of all of the Rex Energy affiliated companies before our initial public offering in July 2007. From March 2004 to September 2006, Mr. Shaner served as the Chief Executive Officer and Chairman of our wholly owned subsidiary, Rex Energy Operating Corp. Since its inception in 1984, Mr. Shaner has served as Chairman and Chief Executive Officer of Shaner Hotels, a privately held hotel company. Mr. Shaner received his Bachelor of Arts degree in History from the University of Alfred.

Benjamin W. Hulburt has been a director of the Company since March 2007. Mr. Hulburt was named Chief Executive Officer of the Company in March 2007 and assumed the duties of President of the Company in February 2008. Mr. Hulburt co-founded the first Rex Energy company in 2001 and has co-founded and has served as an officer of all of the Rex Energy affiliated companies since that time. Beginning in March 2004, Mr. Hulburt served as President of Rex Energy Operating Corp. and was named its Chief Executive Officer in October 2006. From January 2001 to February 2004, Mr. Hulburt served as Chief Financial Officer for Douglas Oil & Gas Limited Partnership. Before November 2000, 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.

Daniel J. Churay has been a director of the Company since October 2007. Since 2002, Mr. Churay has served as the Executive Vice President, General Counsel and Secretary of YRC Worldwide Inc., a publicly traded, Fortune 500 company that is one of the largest transportation services providers in the world. In 2002, Mr. Churay was a Senior Counsel at the law firm of Fulbright & Jaworski L.L.P. From 1998 to 2002, Mr. Churay served as Deputy General Counsel and Assistant Secretary of Baker Hughes Incorporated, a publicly traded supplier of products and technology services and systems to the oil and natural gas industry. From 1995 to 1998, Mr. Churay served as Division Legal Counsel, and later as Chief Corporate Counsel, for Baker Hughes Incorporated. From 1989 to 1995, Mr. Churay was an associate attorney at the law firm of Fulbright & Jaworski L.L.P. Mr. Churay received a B.A. in Economics from The University of Texas at Austin and a Juris Doctorate from University of Houston Law Center.

John W. Higbee has been a director of the Company since October 2007. Mr. Higbee was a partner of Arthur Andersen LLP for over twenty years until his retirement in 2001. At Arthur Andersen, Mr. Higbee served in various management positions, including as the head of the Pittsburgh, Pennsylvania audit practice from 1982

until 1998. Since 2003, Mr. Higbee has served as an independent business consultant to several companies regarding public accounting matters, including Sarbanes-Oxley Act compliance. From September 2004 until August 2006, Mr. Higbee was the Vice President and Chief Financial Officer of the Fullington Auto Bus Company, a privately held company engaged in inter and intra city bus transportation. From April 2002 to August 2003, Mr. Higbee was Chief Financial Officer of Le-Nature’s, Inc., a privately held company engaged in the all-natural beverage business. From February 2004 until March 2006, Mr. Higbee was a director and Chairman of the Audit Committee of World Health Alternatives, Inc., a publicly traded company providing healthcare staffing services to hospitals and other healthcare facilities. From October 2001 to November 2006, Mr. Higbee was a director of Rent-Way, Inc., a publicly traded company that was engaged in the rental-purchase business. Mr. Higbee served on the Audit and Finance committees of Rent-Way’s board of directors, becoming the Chairman of the Audit Committee in December 2003. Mr. Higbee received a B.S. in Accounting from The Pennsylvania State University and is a certified public accountant.

John A. Lombardi has been a director of the Company since April 2007. Since March 2008, Mr. Lombardi has been a principal at the accounting firm of Hill, Barth & King LLC in its Erie, Pennsylvania office. From February 2007 until March 2008, Mr. Lombardi was self-employed as an accounting and financial reporting consultant. Mr. Lombardi was the Senior Vice President and Chief Financial Officer for Rent-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 the Company in March 2007 and was appointed an Executive Vice President in February 2008. Before 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.

William L. Ottaviani was named Chief Operating Officer in November 2007 and Executive Vice President of the Company in February 2008. From September 2007 until his promotion to Chief Operating Officer, Mr. Ottaviani served as Rex Energy’s Senior Vice President of Reservoir Engineering. From 1982 until 2007, Mr. Ottaviani served in various management, engineering, operational, and staff positions for Chevron Corporation and its affiliated companies, with assignments in California, Louisiana, Indonesia and Angola. During his Angola assignment from 2002 until 2007, Ottaviani served as both a senior petroleum engineering advisor and asset development manager. He received his Bachelor of Science degree in Petroleum and Natural Gas Engineering from Pennsylvania State University and his M.B.A. from California State University, Bakersfield.

Christopher K. Hulburt was named Executive Vice President, Secretary and General Counsel of the Company in March 2007. Before that, Mr. Hulburt served as the Vice President, Secretary and General Counsel for each of the Predecessor 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. Before 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.

David E. Pratt was named Vice President and Exploration Manager of the Company in April 2008. Prior to that, Mr. Pratt served as a geologist for the New York State Department of Environmental Conservation, Bureau of Oil and Gas Regulation beginning in November 1999. From December 1990 until February 1999, Mr. Pratt was a regional exploration and development geologist for Cabot Oil and Gas Corporation working in its Appalachian Basin operations. From 1984 until 1990, Mr. Pratt served as an exploration and development geologist for Ultramar Oil and Gas Ltd. working in the Permian Basin, the Gulf Coast region and the Rocky Mountains region. During the period of 1978 until 1984, Mr. Pratt worked as a geologist for Enstar Corporation, Ensource Corporation, Sohio Petroleum and Texaco. Mr. Pratt received his Bachelor of Science degree in Geology from the State University of New York at Albany and a Master’s degree in Geology from Rice University.

Michael S. Carlson was named Vice President & Appalachian Basin District Manager of the Company in March 2007. Before 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 N. Clement was named Vice President & Southwest Region District Manager of the Company in March 2007. Before 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 1997 to April 2004. Mr. Clement received his Bachelor of Science degree in Mechanical Engineering from Texas Tech University.

Jack S. Shawver was named Vice President & Illinois Basin District Manager for the Company in March 2007. Before 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.

The following table sets forth our common stock ownership as of March 31, 2008 for each of our directors, for each of our named executive officers, all of our directors and executive officers as a group, each of our known 5% stockholders and for each Selling Stockholder. Beneficial ownership is determined in accordance with SEC rules and regulations. Unless otherwise indicated and subject to community property laws where applicable, we believe that each of the stockholders named in the table below has sole voting and investment power with respect to the shares indicated as beneficially owned. Unless otherwise indicated, all stockholders set forth below have the same principal business address as the Company. Thomas F. Shields, our former President, resigned from the Company effective February 29, 2008.

The percentage of beneficial ownership of our common stock before this offering is based on 30,794,702 shares of our common stock issued and outstanding as of March 28, 2008 and 34,794,702 shares of our common stock expected to be issued and outstanding after this offering. The percentage of beneficial ownership of our common stock after this offering is based on 34,794,702 shares of our common stock issued and outstanding. The table assumes that the underwriters will not exercise their option to purchase up to 1,200,000 shares of our common stock.

In connection with the Reorganization Transactions, we 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. The Selling Stockholders will sell an aggregate of 4,000,000 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 16,101,703 shares of our common stock. After this offering, the Selling Stockholders will own 12,101,703 shares of our common stock, which will represent approximately 34.8% of our outstanding shares based upon 34,794,702 shares of common stock to be outstanding immediately after completion of this offering.

The shares retained by the Selling Stockholders after completion of this offering will be subject to lock-up for a period of 90 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 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 our amended and restated 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 our amended and restated bylaws, which are filed as exhibits to the registration statement, of which this prospectus forms a part, and to the applicable provisions of Delaware law.

Our amended and restated certificate of incorporation authorizes 100,000,000 shares of common stock, par value $0.001 per share. There are currently 30,794,702 shares of our common stock outstanding. Upon the closing of this offering, there will be 34,794,702 shares of our common stock outstanding, or 35,994,702 shares if the underwriters exercise their over-allotment option in full.

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 amended and restated bylaws, amendments to our amended and restated certificate of incorporation and our amended and restated 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.

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.

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.

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.

All shares of our common stock outstanding upon completion of this offering will be fully paid and non-assessable.

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.

There are currently no shares of our preferred stock outstanding. Upon completion of 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 amended and restated 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.

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:

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.

In addition, some provisions of our amended and restated certificate of incorporation and our amended and restated 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 amended and restated bylaws without further stockholder approval.

Advance notice of director nominations and matters to be acted upon at meetings. Our amended and restated 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.

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. But 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 amended and restated 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.

The transfer agent and registrar for our common stock is ComputerShare Investor Services, LLC.

Our common shares are listed on The NASDAQ Global Market under the symbol “REXX”.

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.

Upon the completion of this offering, we will have 34,794,702 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 4,000,000 million shares of common stock sold by us in this offering.

Of the shares to be outstanding after the closing of this offering, the 8,000,000 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 12,101,703 shares of common stock held by the executives, directors and their affiliates listed as Selling Stockholders 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.

In general, under Rule 144, a person who is one of our affiliates and has beneficially owned those shares of common stock for at least six months would be entitled to sell, within any three-month period, a number of shares that does not exceed the greater of:

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.

A person who is not one of our affiliates, and who is not deemed to have been one of our affiliates at any time during the three months preceding a sale, may sell the shares proposed to be sold according to the following conditions:

In October 2007, we filed a registration statement on Form S-8 under the Securities Act to register 3,079,470 shares of common stock, with respect to options and restricted stock units to be granted, or otherwise, under our Long-Term Incentive Plan. As of April 7, 2008, we have granted stock options and stock appreciation

rights covering 963,200 shares of our common stock. Shares issued upon the exercise of 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.

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 90 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.”

In connection with our initial public offering, we entered into a registration rights agreement with each of the equity owners of the Predecessor Companies regarding the shares of our common stock received by them as a result of the Reorganization Transactions. Subject to certain exceptions set forth in the agreement, we were required to offer all equity owners of the Predecessor Companies the opportunity to register a portion or all of their shares of our common stock received in the Reorganization Transactions in the event that we decided, at any time following the expiration of a 180-day lock-up period following our initial public offering, to file a registration statement with the SEC with respect to any offering of our common stock. The registration rights agreement provides that all registration rights granted under the agreement terminate on the date that the shares received by the equity owners of the Predecessor Companies in connection with the Reorganization Transactions are saleable in a transaction exempt from the registration and prospectus delivery requirements of the Securities Act under Section 4(1) thereof so that all transfer restrictions and restrictive legends with respect thereto are or could be removed upon the consummation of such sale. Because the shares received by the equity owners of the Predecessor Companies as a result of the Reorganization Transactions (other than shares owned by our affiliates) became saleable under Rule 144 on February 15, 2008, such persons are not entitled to registration rights under the agreement, unless we are not in compliance with our SEC filings requirements. At this time, we do not have any other contractual obligations to register our common stock or any other of our securities.

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:

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.

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.

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:

A 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.

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.

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.

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:

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 non-defaulting 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 the public offering price on the cover of this prospectus and to certain dealers at such offering price less a selling concession not in excess of $ per share. 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. KeyBanc Capital Markets Inc. has advised us that the underwriters do not intend sales to discretionary accounts to exceed 5% of the total number of shares offered by them.

We have granted the underwriters an option to purchase up to 1,200,000 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.

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.

We estimate that the total expenses related to this offering payable by us, excluding underwriting discounts and commissions, will be approximately $1.5 million.

We, our executive officers and directors, have agreed with the underwriters, for a period of 90 days after the date of this prospectus, subject to certain exceptions, not to, directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of common stock (including, without limitation, shares of common stock that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the Securities and Exchange Commission and shares of common stock that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common stock, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common stock, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares of common stock or securities convertible, exercisable or exchangeable into common stock or any of our other securities, or (4) publicly disclose the intention to do any of the foregoing, in each case without the prior written consent of KeyBanc Capital Markets Inc.

The 90-day restricted period described in the preceding paragraph will be extended if:

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, unless such extension is waived in writing by KeyBanc Capital Markets Inc.

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.

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 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.

In addition, in connection with this offering, some of the underwriters may engage in passive market making transactions in the common stock on the NASDAQ Global Market, prior to the pricing and completion of the offering. Passive market making consists of displaying bids on the NASDAQ Global Market no higher than the bid prices of independent market makers and making purchases at prices no higher than those independent bids and effected in response to order flow. Net purchases by a passive market maker on each day are limited to a specified percentage of the passive market maker’s average daily trading volume in the common units during a specified period and must be discontinued when that limit is reached. Passive market making may cause the price of the common stock to be higher than the price that otherwise would exist in the open market in the absence of those transactions. If the underwriters commence passive market making transactions, they may discontinue them at any time.

A prospectus in electronic format may be made available on the websites maintained by one or more of the underwriters. The underwriters may agree to allocate a number of shares for sale to their online brokerage account holders. KeyBanc Capital Markets Inc. will allocate common units to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.

Other than the prospectus in electronic format, the information on any underwriter’s web site and any information contained in any other web site maintained by an underwriter is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter in its capacity as an underwriter and should not be relied upon by investors.

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.

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 administrative agent and a lender under company’s $200 million senior credit facility.

Because an affiliate of KeyBanc Capital Markets Inc. is a lender under our $200 million senior credit facility, and will receive more than 10% of the net proceeds of this offering when we initially use a portion of the net proceeds of this offering to repay amounts outstanding under our senior credit facility, KeyBanc Capital

Markets Inc. may be deemed to have a “conflict of interest” with us under Rule 2710(h)(1) of the Financial Industry Regulatory Authority, or the FINRA. When a FINRA 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 FINRA. In accordance with this rule, has assumed the responsibilities of acting as a qualified independent underwriter. In its role as qualified independent underwriter, 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. will not receive any additional fees for serving as qualified independent underwriter in connection with this offering. We have agreed to indemnify against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act.

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 23,612 shares of our common stock. Vinson & Elkins L.L.P., Houston, Texas, will act as counsel to the underwriters.

The consolidated and combined financial statements of Rex Energy Corporation as of December 31, 2007 and for the year ended December 31, 2007 and the combined financial statements of the Predecessor Companies of Rex Energy Corporation as of December 31, 2006, and for each of the two years in the period ended December 31, 2006, have been incorporated in this prospectus in reliance upon the report of Malin, Bergquist & Company, LLP, an independent registered public accounting firm, incorporated by reference in this prospectus in reliance upon the authority of such firm as experts in accounting and auditing.

The information included in this prospectus as of December 31, 2007, 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.

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document previously filed by us at the SEC’s Public Reference Room 100, F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at l-800-SEC-0330. Our filings with the SEC are also available to the public on the SEC’s Internet website at http://www.sec.gov.

We have filed with the SEC a registration statement under the Securities Act that registers the distribution of the securities offered hereby. The registration statement, including the attached exhibits and schedules, contains additional relevant information about us and the securities being offered. This prospectus, which forms part of the registration statement, omits certain of the information contained in the registration statement in accordance with the rules and regulations of the SEC. Reference is hereby made to the registration statement and related exhibits for further information with respect to us and the securities offered hereby. Statements contained in this prospectus concerning the provisions of any document are not necessarily complete and, in each instance, reference is made to the copy of such document filed as an exhibit to the registration statement or otherwise filed with the SEC. Each such statement is qualified in its entirety by such reference.

We incorporate into this prospectus by reference the following documents filed by us with the SEC, each of which should be considered an important part of this prospectus:

Any person, including any beneficial owner, to whom this prospectus is delivered may request copies of this prospectus and any of the documents incorporated by reference in this prospectus, without charge, by written or oral request directed to Corporate Secretary, 1975 Waddle Road, State College, PA 16803, telephone (814) 278-7267, on the “Investor Relations” section of our website at http://www.rexenergy.com or from the SEC through the SEC’s website at the address provided above. Documents incorporated by reference are available without charge, excluding any exhibits to those documents unless the exhibit is specifically incorporated by reference into those documents.

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2007, to the Rex Energy Corporation (Rex) interest 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 have been prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission and, with the exception of the exclusion of future income taxes, conform to the Statement of Financial Accounting Standards No. 69. Definitions are presented immediately following this letter.

As presented in the accompanying summary projections, Tables I through IV, we estimate the net reserves and future net revenue to the Rex interest in these properties, as of December 31, 2007, to be:

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. 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. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk. As shown in the Table of Contents, for each region this report includes summary projections of reserves and revenue by reserves category along with one-line summaries of basic data, reserves, and economics by lease.

Future gross revenue to the Rex 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. 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, 2007, West Texas Intermediate posted price of $92.50 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, 2007, Henry Hub spot market price of $6.795 per MMBTU and are adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the lives of the properties.

Lease and well operating costs used in this report are based on operating expense records of Rex. 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 direct lease- and field-level costs and Rex’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Lease and well operating costs are held constant throughout the lives of the properties. Capital costs are included as required for workovers, new development wells, and production equipment. The future capital costs are held constant to the date of expenditure.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Rex 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 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 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.

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.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

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 or 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.

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.

PV-10 or present value of estimated future cash flows. An estimate of the present value of the estimated future cash flows 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 cash flows 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 cash flows 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. Proved developed reserves expected to be recovered from zones behind casing in existing wells.

Proved developed producing reserves. 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. 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.

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.

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 SEC registration fee, the FINRA fee and the Nasdaq Global Market listing fee.

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.

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.

We have entered into an agreement with each of our independent directors that provide that the independent director will be entitled to the limitations of liability and the right to indemnification against expenses and damages in connection with claims against the independent director relating to the independent director’s service to us to the fullest extent permitted by our certificate of incorporation and our amended and restated bylaws, the Delaware General Corporation Law and other applicable law. In addition, employment agreements with certain of our executive officers provide that we will indemnify the executive officer to the fullest extent permitted by the Delaware General Corporation Law, or our certificate of incorporation and our amended and restated bylaws, whichever affords the greater protection to the executive officer.

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 to be filed as Exhibit 1.1 hereto.

We maintain directors and officers liability insurance for the benefit of our directors and officers.

Certain transaction were completed simultaneously with the closing of our initial public offering on July 24, 2007. 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 received 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.

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.

(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.

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, Commonwealth of Pennsylvania on April 7, 2008.

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Benjamin W. Hulburt and Christopher K. Hulburt and each of them to act without the other, his true and lawful attorney-in-fact and agent, with full power of substitution, for him and in his name, place and stead, in any and all capacities, to sign and file any and all amendments (including post-effective amendments) to this registration statement, and to sign any registration statement for the same offering covered by this registration statement that is to be effective upon filing pursuant to Rule 462(b) promulgated under the Securities Act of 1933, and all post-effective amendments thereto, and to file the same, with all exhibits thereto, and all documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, full power and authority to do and perform each and every other act on behalf of the undersigned required to be done in connection therewith.

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.


Large accelerated filer ¨		Accelerated filer ¨
Non-accelerated filer x		Smaller reporting company ¨
(Do not check if a smaller reporting company)



Title of Each Class of Securities to be Registered	Amount to be Registered⁽¹⁾	Proposed Maximum Aggregate Offering Price per Security⁽¹⁾⁽²⁾	Proposed Maximum Aggregate Offering Price⁽¹⁾	Amount of Registration Fee
Common Stock, $.001 par value	9,200,000	$16.37	$150,604,000	$5,918


	Per Share	Total
Price to the public	$	$

Underwriting discount	$	$

Offering proceeds, before expenses, to Rex Energy Corporation	$	$

Offering proceeds, before expenses, to selling stockholders	$	$


PROSPECTUS SUMMARY		1
RISK FACTORS		14
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		25
USE OF PROCEEDS		26
CAPITALIZATION		27
PRICE RANGE OF COMMON STOCK		28
DIVIDEND POLICY		28
SELECTED HISTORICAL FINANCIAL AND OPERATING DATA		29
THE REORGANIZATION TRANSACTIONS		34
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		35
BUSINESS		51
DIRECTORS AND EXECUTIVE OFFICERS		72
PRINCIPAL AND SELLING STOCKHOLDERS		75
DESCRIPTION OF CAPITAL STOCK		77
SHARES ELIGIBLE FOR FUTURE SALE		80
MATERIAL U.S. FEDERAL TAX CONSIDERATIONS FOR NON-U.S. HOLDERS OF COMMON STOCK		82
UNDERWRITING		85
LEGAL MATTERS		89
EXPERTS		89
WHERE YOU CAN FIND MORE INFORMATION		89
INCORPORATION OF CERTAIN DOCUMENTS		89
SUMMARY RESERVE REPORT		A-1
GLOSSARY OF OIL AND NATURAL GAS TERMS		B-1


	As of December 31, 2007
	Actual (Audited)			As Adjusted (Unaudited)
	(In thousands)
Cash and cash equivalents	$	1,085		$	38,257
Total debt (including current maturities)⁽¹⁾		27,236			—
Owners’ Equity:
Common stock, $.001 par value; 100,000,000 authorized; 30,794,702 issued and outstanding actual; 34,794,702 issued and outstanding as adjusted		31			35
Preferred stock, $.001 par value; 100,000 authorized; none issued and outstanding		—			—
Additional paid-in capital		175,170			239,574
Accumulated other comprehensive income (loss)		(124	)		(124	)
Accumulated deficit		(10,640	)		(10,640	)

Total Owners’ Equity	$	164,437		$	228,845


2007	High		Low
Third Quarter	$	10.50	$	7.50
Fourth Quarter	$	11.99	$	8.00

2008	High		Low
First Quarter	$	17.92	$	9.36
Second Quarter (through April 4, 2008)	$	17.50	$	16.09


	Rex Energy Corporation Consolidated and Combined			Rex Energy Corporation Combined Predecessor Companies
	Year Ended December 31, ($ and shares in Thousands)
	2007			2006			2005			2004			2003
													(unaudited)
Statement of operations data:
Operating Revenue:
Oil and Natural Gas Sales	$	63,525		$	43,596		$	29,518		$	14,159		$	5,193
Other Revenue		452			470			270			697			928
Realized Gain (Loss) from Derivatives		(6,198	)		(4,436	)		(7,930	)		(942	)		—

Total Operating Revenue		57,779			39,630			21,858			13,914			6,121

Operating Expenses:
Production Lease Operating and Production Taxes		24,477			15,234			11,721			6,708			2,204
General and Administrative		8,587			6,212			3,789			2,229			1,177
Depletion, Depreciation, Amortization and Accretion		19,622			11,223			3,320			2,039			1,015
Exploration		2,948			—			107			3,024			—

Total Operating Expenses		55,634			32,669			18,937			14,000			4,396

Income (Loss) from Operations		2,145			6,961			2,921			(86	)		1,725

Other Income (Expenses):
Interest Income		15			94			444			19			42
Interest Expense		(5,646	)		(6,110	)		(1,697	)		(867	)		(171	)
Gain on Sale of Oil and Gas Properties		185			91			1,016			659			—
Unrealized Gain (Loss) from Derivatives		(26,250	)		5,043			(5,541	)		(1,396	)		—
Other Income (Expense)		171			(132	)		216			(21	)		—

Total Other Income (Expense)		(31,525	)		(1,014	)		(5,562	)		(1,606	)		(129	)

Net Income (Loss) Before Minority Interests and Income Tax		(29,380	)		5,947			(2,641	)		(1,692	)		1,596
Minority Interests Share of (Net Income) Loss		6,152			(2,133	)		(2,304	)		2,062			(968	)
Income Tax Benefit		7,017			—			—			—			—

Net Income (Loss)	$	(16,211	)	$	3,814		$	(4,945	)	$	370		$	628

Earnings per common share for the five month period ended December 31, 2007:
Net loss for the five month period ended December 31, 2007	$	(10,640	)
Basic and Fully Diluted earnings per common share	$	(0.35	)		—			—			—			—
Weighted average shares of common stock outstanding		30,795			—			—			—			—
Other Financial Data:
EBITDAX (before minority interests)	$	25,282		$	18,143		$	7,580		$	5,615		$	804
Cash Flow Data:
Cash provided by operating activities		17,555			12,920			9,527			5,983			631
Cash used in investing activities		(40,102	)		(94,446	)		(19,404	)		(9,612	)		(6,090	)
Cash provided by financing activities		23,032			79,438			9,772			5,457			5,913
Balance Sheet Data:
Cash and cash equivalents		1,085			600			3,188			3,217			1,347
Property and Equipment (net of accumulated depreciation, depletion and amortization)		217,532			133,631			42,265			24,573			15,826
Total Assets		268,264			144,611			55,291			33,311			19,507
Current liabilities, including current portion of long-term debt		20,736			53,684			32,297			13,672			2,864
Long-Term Debt, net of current maturities		27,207			45,442			3,360			3,000			4,259
Total Liabilities		103,827			108,639			42,080			18,416			7,611
Minority Interests		—			36,589			24,130			11,696			9,561

Owners’ Equity		164,437			(617	)		(10,920	)		3,198			2,336


	Year Ended December 31,
	2007			2006			2005			2004			2003
Net Income (Loss)	$	(16,211	)	$	3,814		$	(4,945	)	$	370		$	628
Add Back Depletion, Depreciation, Amortization and Accretion		19,622			11,223			3,320			2,039			1,015
Add Back Non-Cash Compensation Expense		211			—			—			—			—
Add Back Interest Expense		5,646			6,110			1,697			867			171
Add Back Exploration & Impairment Expenses		2,948			—			107			3,024			—
Less Interest Income		(15	)		(94	)		(444	)		(19	)		(42	)
Add Back Unrealized Losses (Gains) from Financial Derivatives		26,250			(5,043	)		5,541			1,396			—
Add Back Minority Interest Share of Net Income (Loss)		(6,152	)		2,133			2,304			(2,062	)		(968	)
Add Back (Less) Income Tax Expense (Benefit)		(7,017	)		—			—			—

EBITDAX Before Minority Interests	$	25,282		$	18,143		$	7,580		$	5,615		$	804


	2007		% of Total		2006		% of Total		2005		% of Total
Revenue from Oil Sales	$	55,542	86.8	%	$	35,790	81.2	%	$	20,355	68.3	%
Revenue from Natural Gas Sales		7,983	12.5	%		7,806	17.7	%		9,163	30.8	%
Other		452	0.7	%		470	1.1	%		270	0.9	%

Total	$	63,977	100.0	%	$	44,066	100.0	%	$	29,788	100.0	%


	Performance Measurements
	Years Ended December 31,
	2007			2006			2005
EBITDAX ($ in Thousands)	$	25,282		$	18,143		$	7,580
Production Cost per BOE	$	24.28		$	19.72		$	20.70
Total Proved Reserves (MMBOE)		15.9			14.5			9.1
G&A as a Percentage of Operating Revenue		14.9	%		15.7	%		17.3	%


	Payments Due Period
	2008		2009 and 2010		2011 and 2012		Thereafter		Total
	(in thousands)
Bank debt	$	29	$	21	$	—	$	27,186	$	27,236
Operating leases		354		772		709		436		2,271
Drilling contracts		1,700		3,400		3,400		1,700		10,200
Derivative obligations^(a)		10,873		18,842		—		—		29,715
Asset retirement obligation liability		—		—		—		6,396		6,396

Total contractual obligations	$	12,956	$	23,035	$	4,109	$	35,718	$	75,818


	For the Years Ended December 31,
	2007 (actual)		2008 (estimated)
Capital Expenditures
Illinois Basin Conventional Oil Operations	$	14.8	$	16.5
Lawrence Field ASP Flood Project		4.5		29.9
Shale Projects		3.2		16.1
Appalachian Basin Operations		5.2		7.1
Southwestern Region Operations		4.0		9.9
Acquisitions of proved oil and gas properties		2.3		—
Acquisitions and leasing of undeveloped properties		5.4		58.6
Other Capital Expenditures		1.0		0.6

Total Capital Expenditures	$	40.4	$	138.7


	Production and Revenue by Region For the Years Ended December 31,
	2007		2006		2005
Appalachian Region:
Revenue	$	5,725	$	5,460	$	6,470
Oil Production (Bbls)		—		—		—
Natural Gas Production (Mcf)		786,095		707,755		701,265
Total Production (BOE)⁽¹⁾		131,016		117,959		116,878
Oil Average Sales Price	$	—	$	—	$	—
Natural Gas Average Sales Price	$	7.28	$	7.71	$	9.23

Illinois Region:
Revenue	$	52,408	$	33,328	$	18,486
Oil Production (Bbls)		769,911		546,231		343,225
Natural Gas Production (Mcf)		—		—		—
Total Production (BOE)⁽¹⁾		769,911		546,231		343,225
Oil Average Sales Price	$	68.07	$	61.02	$	53.86
Natural Gas Average Sales Price	$	—	$	—	$	—

Southwestern Region:
Revenue	$	5,392	$	4,808	$	4,562
Oil Production (Bbls)		44,946		41,239		35,729
Natural Gas Production (Mcf)		373,904		401,739		423,478
Total Production (BOE)⁽¹⁾		107,263		108,196		106,309
Oil Average Sales Price	$	69.73	$	59.70	$	52.29
Natural Gas Average Sales Price	$	6.04	$	5.84	$	6.36

Total Company:
Revenue	$	63,525	$	43,596	$	29,518
Oil Production (Bbls)		814,857		587,470		378,954
Natural Gas Production (Mcf)		1,159,999		1,109,494		1,124,743
Total Production (BOE)⁽¹⁾		1,008,190		772,386		566,411
Oil Average Sales Price	$	68.16	$	60.92	$	53.71
Natural Gas Average Sales Price	$	6.88	$	7.04	$	8.15


Division	Average Daily Production (BOE per day)	Total Production (BOE)	Percent of Total Production		Total Proved Reserved (BOE)	Percentage of Total Proved Reserves
Illinois Basin	2,109	769,911	76.4	%	11,962,181	75.4	%
Appalachian Basin	359	131,016	13.0	%	2,119,316	13.3	%
Southwestern Region	294	107,263	10.6	%	1,786,162	11.3	%

Total	2,762	1,008,190	100.0	%	15,867,659	100.0	%


	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	34,610	18,115	35,218	15,045	69,828	33,160	425	⁽³⁾	186	—	—

Illinois Basin
Illinois	12,752	4,481	34,580	19,476	47,332	23,957	—		—	1,180	1,173
Indiana	293,681	79,987	12,455	11,685	306,136	91,672	—		—	221	216
Kentucky	1,244	474	821	28	2,065	502	—		—	—	—

Total Illinois Basin	307,677	84,942	47,856	31,189	355,533	116,131	—		—	1,401	1,389

Southwestern Region
Texas	1,440	1,160	9,199	6,245	10,639	7,405	21		7	43	40
New Mexico	437	326	4,320	1,902	4,757	2,228	35		7	16	4

Total Southwestern Region	1,877	1,486	13,519	8,147	15,396	9,633	56		14	59	44

Total	344,164	104,543	96,593	54,381	440,757	158,924	481		200	1,460	1,433


	Expiring Acreage
Year Ending December 31,	Gross	Net
2008	17,282	4,416
2009	76,401	20,518
2010	127,715	39,436
2011	79,439	22,241
Thereafter	27,781	12,242

Total	328,618	98,853


Name	Age	Position with the Company
Lance T. Shaner	54	Director and Chairman
Benjamin W. Hulburt	34	Director, President and Chief Executive Officer
Daniel J. Churay	45	Director
John W. Higbee	65	Director
John A. Lombardi	42	Director
Thomas C. Stabley	37	Executive Vice President and Chief Financial Officer
William L. Ottaviani	47	Executive Vice President and Chief Operating Officer
Christopher K. Hulburt	37	Executive Vice President, Secretary and General Counsel
David E. Pratt	56	Vice President & Exploration Manager
Michael S. Carlson	52	Vice President & Appalachian District Manager
Joe N. Clement	50	Vice President & Southwest Region District Manager
Jack S. Shawver	50	Vice President & Illinois Basin District Manager


Beneficial Owner	Shares Beneficially Owned Prior to Offering				Shares Offered		Shares Beneficially Owned After Offering
Beneficial Owner	Number		Percentage		Shares Offered		Number		Percentage
Directors and Executive Officers:
Lance T. Shaner	12,595,762	⁽¹⁾	40.9	%	3,425,000	⁽²⁾	9,170,762		26.4	%
Benjamin W. Hulburt	1,381,717	⁽³⁾	4.5	%	125,000		1,256,717		3.6	%
Thomas F. Shields	1,063,124	⁽⁴⁾	3.5	%	—		1,063,124		3.1	%
Thomas C. Stabley	588,538	⁽⁵⁾	1.9	%	125,000		463,538		1.3	%
Christopher K. Hulburt	571,075		1.9	%	125,000		446,075		1.3	%
Jack S. Shawver	476,230		1.5	%	100,000		376,230		1.1	%
Michael S. Carlson	488,381		1.6	%	100,000		388,381		1.1	%
Daniel J. Churay	—		—		—		—		—
John W. Higbee	—		—		—		—		—
John A. Lombardi	—		—		—		—		—

All Executive Officers and Directors as group (9 persons)	16,101,703	⁽⁶⁾	52.3	%	4,000,000		12,101,703	⁽⁹⁾	34.8	%
Goldman Sachs Asset Management, L.P.⁽⁷⁾	2,085,230		6.8	%	—		2,085,230		6.0	%
Shaner Family Partners Limited Partnership	1,314,903		4.3	%	666,000		648,903		1.9	%
The Lance T. Shaner Irrevocable Grandchildren’s Trust II	95,454		*		44,000		51,454		*
Shaner & Hulburt Capital Partners Limited Partnership	276,927		*		276,927		0		—
Rexguard, LLC	472,209		1.5	%	472,209		0		—


Underwriter		Number of Shares
KeyBanc Capital Markets Inc.





Total		8,000,000


	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


	Net Reserves		Future Net Revenue ($)
Category	Oil (Barrels)	Gas (MCF)	Total	Present Worth at 10%
Proved Developed
Producing	9,331,722	12,111,473	520,786,100	293,914,500
Non-Producing	921,665	721,448	55,765,300	35,012,700
Proved Undeveloped	2,522,851	5,715,605	145,698,400	63,148,100

Total Proved	12,776,238	18,548,526	722,249,800	392,075,300


NETHERLAND, SEWELL & ASSOCIATES, INC.

By:		/S/ C.H. (SCOTT) REES III, P.E.
		C.H. (Scott) Rees III, P.E.
		Chairman and Chief Executive Officer

By:		/S/ MIKE K. NORTON, P.G.
		Mike K. Norton, P.G.
		Senior Vice President

By:		/S/ MATTHEW T. BROGDON, P.E.
		Matthew T. Brogdon, P.E.
		Vice President


Securities and Exchange Commission registration fee		$ 5,918
Financial Industry Regulatory Authority fee		14,412
Nasdaq Global Market filing fee		*
Printing and engraving expenses		*
Accounting fees and expenses		*
Legal fees and expenses		*
Transfer agent and registrar fees		*
Miscellaneous fees and expenses		*

TOTAL		*


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 (incorporated by reference to Exhibit 2.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

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 (incorporated by reference to Exhibit 2.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).


Exhibit Number		Exhibit Title

2.3		Contribution Agreement among Lance T. Shaner, Benjamin W. Hulburt, Michael J. Carlson, Jack Shawver, Thomas F. Shields, Thomas C. Stabley, Christopher K. Hulburt, PennTex Energy Inc. and Rex Energy Corporation (incorporated by reference to Exhibit 2.3 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

3.1		Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.2		Amendment to Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

3.3		Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

4.1		Form of Specimen Common Stock Certificate of Rex Energy Corporation (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

4.2		Form of Registration Rights Agreement (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

5.1*		Opinion of Fulbright & Jaworski L.L.P.

10.1		Rex Energy Corporation 2007 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to our Registration Statement on Form S-1/A (File No. 333-142430) as filed with the SEC on June 11, 2007).

10.2		Amended and Restated Employment Agreement by and between Jack S. Shawver and Rex Energy Operating Corp. dated May 18, 2006 (incorporated by reference to Exhibit 10.4 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

10.3		Consent Decree (incorporated by reference to Exhibit 10.5 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

10.4		Independent Director Agreement with John A. Lombardi dated April 1, 2007 (incorporated by reference to Exhibit 10.6 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

10.5		Service Provider Agreement, dated April 1, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.7 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

10.6		Service Level Agreement, dated April 13, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

10.7		Letter Agreement, dated April 13, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

10.8		Lease Agreement, dated September 1, 2006, between Shaner Brothers, LLC and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.10 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).


Exhibit Number		Exhibit Title

10.9		Promissory Note, dated September 1, 2006, by Rex Energy Operating Corp. to Shaner Brothers, LLC. (incorporated by reference to Exhibit 10.11 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.10		Summary of oral month-to-month administrative services agreement between Shaner Solutions Limited Partnership and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.12 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.11		Summary of oral month-to-month agreement regarding use of airplane between Charlie Brown Air Corp. and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.13 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.12		Summary of oral working capital loan agreement between Lance T. Shaner and PennTex Resources Illinois, Inc. (incorporated by reference to Exhibit 10.14 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.13		Amended and Restated Limited Liability Company Agreement, dated June 21, 2007, of L&B Air LLC (incorporated by reference to Exhibit 10.15 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.14		Amended and Restated Limited Partnership Agreement, dated June 21, 2007, of Charlie Brown II Limited Partnership (incorporated by reference to Exhibit 10.16 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.15		Promissory Note, dated June 21, 2007, by Rex Energy Operating Corp. to Lance T. Shaner (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.16		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 (incorporated by reference to Exhibit 10.18 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.17		Employment Agreement by and between Benjamin W. Hulburt and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).

10.18		Employment Agreement by and between Thomas F. Shields and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).

10.19		Employment Agreement by and between Thomas C. Stabley and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).

10.20		Employment Agreement by and between Christopher K. Hulburt and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).

10.21		Employment Agreement by and between William L. Ottaviani and Rex Energy Operating Corp. dated August 8, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on August 14, 2007).

10.22		Credit Agreement, dated as of September 28, 2007, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, BNP Paribas, as Syndication Agent, Sovereign Bank, as Documentation Agent and The Lenders Party Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on October 3, 2007).


Exhibit Number		Exhibit Title

10.23		Guaranty and Collateral Agreement, dated as of September 28, 2007, made by Rex Energy Corporation and each of the other grantors (as defined therein) in favor of KeyBank National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K as filed with the SEC on October 3, 2007).

10.24		Independent Director Agreement by and between Rex Energy Corporation and Daniel J. Churay, effective as of October 19, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on October 19, 2007).

10.25		Independent Director Agreement by and between Rex Energy Corporation and John W. Higbee effective as of October 17, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on October 19, 2007).

10.26		Rex Energy Corporation Director Compensation Plan Effective As of January 1, 2008 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on December 11, 2007).

10.27		Amended and Restated Separation Agreement dated February 29, 2008 between Rex Energy Operating Corp. and Thomas F. Shields (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on March 3, 2008).

10.28		Form of Nonqualified Stock Option Award Agreement for employee common stock option awards under Rex Energy 2007 Long-Term Incentive Plan. (incorporated by reference to Exhibit 10.28 to our Annual Report on Form 10-K filed with the SEC on March 31, 2008).

10.29		Form of Nonqualified Stock Option Award Agreement for non-employee director common stock option awards under Rex Energy 2007 Long-Term Incentive Plan. (incorporated by reference to Exhibit 10.29 to our Annual Report on Form 10-K filed with the SEC on March 31, 2008).

10.30		Form of Stock Appreciation Right Award Agreement under Rex Energy 2007 Long-Term Incentive Plan. (incorporated by reference to Exhibit 10.30 to our Annual Report on Form 10-K filed with the SEC on March 31, 2008).

21.1		Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.1 to our Annual Report on Form 10-K filed with the SEC on March 31, 2008).

23.1*		Consent of Malin, Bergquist & Company, LLP.

23.2*		Consent of Netherland, Sewell & Associates, Inc.

23.3*		Consent of Surtek, Inc.

23.4*		Consent of Fulbright & Jaworski L.L.P. (included in Exhibit 5.1).

24.1*		Power of Attorney (included in signature page).


REX ENERGY CORPORATION (Registrant)

By:		/S/ BENJAMIN W. HULBURT
Name:		Benjamin W. Hulburt
Title:		President and Chief Executive Officer


Signature	Title	Date

/S/ LANCE T. SHANER Lance T. Shaner	Chairman	April 7, 2008

/S/ DANIEL J. CHURAY Daniel J. Churay	Director	April 7, 2008

/S/ JOHN W. HIGBEE John W. Higbee	Director	April 7, 2008

/S/ JOHN A. LOMBARDI John A. Lombardi	Director	April 7, 2008

/S/ BENJAMIN W. HULBURT Benjamin W. Hulburt	President, Chief Executive Officer and Director (Principal Executive Officer)	April 7, 2008

/S/ THOMAS C. STABLEY Thomas C. Stabley	Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	April 7, 2008


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 (incorporated by reference to Exhibit 2.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

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 (incorporated by reference to Exhibit 2.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

2.3		Contribution Agreement among Lance T. Shaner, Benjamin W. Hulburt, Michael J. Carlson, Jack Shawver, Thomas F. Shields, Thomas C. Stabley, Christopher K. Hulburt, PennTex Energy Inc. and Rex Energy Corporation (incorporated by reference to Exhibit 2.3 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

3.1		Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

3.2		Amendment to Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

3.3		Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

4.1		Form of Specimen Common Stock Certificate of Rex Energy Corporation (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

4.2		Form of Registration Rights Agreement (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

5.1*		Opinion of Fulbright & Jaworski L.L.P.

10.1		Rex Energy Corporation 2007 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to our Registration Statement on Form S-1/A (File No. 333-142430) as filed with the SEC on June 11, 2007).

10.2		Amended and Restated Employment Agreement by and between Jack S. Shawver and Rex Energy Operating Corp. dated May 18, 2006 (incorporated by reference to Exhibit 10.4 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

10.3		Consent Decree (incorporated by reference to Exhibit 10.5 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).