10-K

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

þ Annual Report Pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2007

o Transition Report Pursuant to Section 13 of 15(d) of the Securities Exchange Act of 1934

For the transition period from                      to                     

Commission File Number: 000 — 13305

PARALLEL PETROLEUM CORPORATION

(Exact Name of Registrant as Specified in its Charter)

Delaware	75-1971716
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

1004 N. Big Spring, Suite 400 Midland, Texas	79701
(Address of Principal Executive Offices	(Zip Code)

Registrant’s Telephone Number, Including Area Code: (432) 684-3727

Securities Registered Pursuant to Section 12(b) of the Act:

Common Stock, $.01 par value
Common Stock Purchase Warrants
Rights to Purchase Series A Preferred Stock
(Title of Class)

Securities Registered Pursuant to Section 12(g) of the Act: None

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o               No þ

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o               No þ

     Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ               No o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

     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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o               No þ

     The aggregate market value of voting and non-voting common equity held by non-affiliates of the Registrant as of February 1, 2008 was approximately $578,055,034, based on the closing price of the common stock on the same date.

     At February 1, 2008 there were 41,252,644 shares of common stock outstanding.

FORM 10-K

PARALLEL PETROLEUM CORPORATION

TABLE OF CONTENTS

Item No.		Page
	PART I
Item 1.	Business		1
Item 1A.	Risk Factors		13
Item 1B.	Unresolved Staff Comments		25
Item 2.	Properties		26
Item 3.	Legal Proceedings		30
Item 4.	Submission of Matters to a Vote of Security Holders		30
	PART II
Item 5.	Market for Registant’s Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities		30
Item 6.	Selected Financial Data		32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		33
Item 7A.	Quantitive and Qualitative Disclosure About Market Risk		54
Item 8.	Financial Statements and Supplementary Data		56
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		56
Item 9A.	Controls and Procedures		56
Item 9B.	Other Information		58
	PART III
Item 10.	Directors and Executive Officers of the Registrant		59
Item 11.	Executive Compensation		63
Item 12.	Security Ownership of Certain Benefical Owners and Management and Related Stockholder Matters		87
Item 13.	Certain Relationships and Related Transactions, and Director Independence		90
Item 14.	Principal Accountant Fees and Services		92
	PART IV
Item 15.	Exhibits and Financial Statement Schedules		93
Hagerman Gas Gathering System Joint Venture Agreement
Consent of BDO Seidman, LLP
Consent of Cawley Gillespie & Associates Inc. Independent Petroleum Engineers
Certification of Principal Executive Officer Pursuant to Section 302
Certification of Principal Financial Officer Pursuant to Section 302
Certification of Chief Executive Officer Pursuant to Section 906
Certification of Chief Financial Officer Pursuant to Section 906

(i)

Cautionary Statement Regarding Forward -Looking Statements

     Some statements contained in this Annual Report on Form 10-K are “forward-looking statements”. These forward-looking statements relate to, among others, the following:

• our future financial and operating performance and results;

• our drilling plans and ability to secure drilling rigs to effectuate our plans;

• production volumes;

• availability of natural gas gathering and transmission facilities;

• our business strategy;

• market prices;

• sources and availability of funds necessary to conduct operations and complete acquisitions;

• development costs;

• number and location of planned wells;

• our future commodity price risk management activities;

• our plans and forecasts; and

• any other statements that are not historical facts.

     We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

     We use the words “may”, “will”, “expect”, “could,” “anticipate,” “estimate”, “believe”, “continue”, “intend”, “plan”, “budget”, “future”, “reserves” and other similar words to identify forward-looking statements. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations. We believe the assumptions and expectations reflected in these forward-looking statements are reasonable. However, we cannot give any assurance that our assumptions and expectations will prove to be correct or that we will be able to take any actions that are presently planned. All of these statements involve assumptions of future events and risks and uncertainties. Risks and uncertainties associated with forward-looking statements include, but are not limited to:

• fluctuations in prices of oil and natural gas;

• dependence on key personnel;

• reliance on technological development and technology development programs;

• demand for oil and natural gas;

• losses due to future litigation;

• future capital requirements and availability of financing;

• geological concentration of our reserves;

• risks associated with drilling and operating wells;

• competition;

(ii)

• general economic conditions;

• governmental regulations and liability for environmental matters;

• receipt of amounts owed to us by customers and counterparties to our derivative contracts;

• hedging decisions, including whether or not to hedge;

• terrorist attacks or war;

• actions of third party co-owners of interests in properties in which we also own an interest; and

• fluctuations in interest rates and availability of capital.

     For these and other reasons, actual results may differ materially from those projected or implied. We believe it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict or over which we have no control. We caution you against putting undue reliance on forward-looking statements or projecting any future results based on such statements.

     Before you invest in our common stock or our 10¹/4% senior notes, you should be aware that there are various risks associated with an investment. We have described some of these risks in other sections of this Annual Report on Form 10-K and under Item 1A. Risk Factors, beginning on page 13.

     Unless the context requires otherwise, references in this Annual Report on Form 10-K to “we”, “us”, “our”, “Parallel” or “Company” mean the registrant, Parallel Petroleum Corporation and, where applicable, its former consolidated subsidiaries.

(iii)

PART I

ITEM 1. BUSINESS

About Our Company

     We are a Midland, Texas-based independent oil and natural gas exploration and production company focused on the acquisition, development and exploitation of long-lived oil and natural gas reserves and, to a lesser extent, exploring for new oil and natural gas reserves. The majority of our current producing properties are in the Permian Basin of West Texas and New Mexico, the Fort Worth Basin of North Texas, and the onshore Gulf Coast area of South Texas. We are a publicly traded company listed on Nasdaq under the ticker symbol PLLL.

     Throughout this report, we refer to some terms that are commonly used and understood in the oil and natural gas industry. These terms are:

• Bbl or Bbls — barrel or barrels of oil or other liquid hydrocarbons;

• Bcf — billion cubic feet of natural gas;

• BOE — equivalent barrel of oil or 6 Mcf of natural gas for one barrel of oil;

• MBbls — thousand barrels of oil or other liquid hydrocarbons;

• MBoe — thousand barrels of oil equivalent;

• MMBbls — million barrels of oil or other liquid hydrocarbons;

• MMBoe — million barrels of oil equivalent;

• MMBtu — million British thermal units;

• Mcf — thousand cubic feet of natural gas; and

• MMcf — million cubic feet of natural gas.

     Parallel was incorporated in Texas on November 26, 1979, and reincorporated in the State of Delaware on December 18, 1984.

     Our executive offices are located at 1004 N. Big Spring, Suite 400, Midland, Texas 79701. Our telephone number is (432) 684-3727.

Available Information

     You may read and copy any materials we file with, or furnish to, the Securities and Exchange Commission at the SEC’s public reference facilities at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference facilities by calling the SEC at 1-800-SEC-0330. The SEC maintains a website (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, including Parallel, that file electronically with the SEC.

     Our website address is www.plll.com. Information on our website or any other website is not incorporated by reference into this Annual Report on Form 10-K and does not constitute a part of this Annual Report on Form 10-K.

     We make available free of charge on our Internet website our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

     We will provide electronic or paper copies of our SEC filings free of charge upon request made to Cindy Thomason, Manager of Investor Relations, cindyt@plll.com, 1-800-299-3727.

(1)

Developments in 2007; 2008 Capital Budget

     On July 31, 2007, we completed a private offering of unsecured senior notes (the “senior notes” or “10¹/4% senior notes”) in the principal amount of $150.0 million. The senior notes mature on August 1, 2014 and bear interest at 10.25% which is payable semi-annually beginning on February 1, 2008. Prior to August 1, 2010, we may redeem up to 35% of the senior notes for a price equal to 110.250% of the original principal amount of the senior notes with the proceeds of certain equity offerings. On or after August 1, 2011 we may redeem all or some of the senior notes at a redemption price that will decrease from 105.125% of the principal amount of the senior notes to 100% of the principal amount on August 1, 2013. In addition, prior to August 1, 2011, we may redeem some or all of the senior notes at a redemption price equal to 100% of the principal amount of the senior notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. We have agreed to use our reasonable best efforts to exchange the senior notes for registered, freely tradable notes which otherwise have substantially identical terms to the senior notes within 210 days of July 31, 2007. A registration statement on Form S-4 allowing holders of the senior notes to exchange the notes for freely tradable notes became effective on January 29, 2008.

     On November 30, 2007, we entered into a Fourth Amendment to our Third Amended and Restated Credit Agreement, dated December 23, 2005. In addition to amending certain covenants, our borrowing base under the revolving credit facility was increased from $150.0 million to $200.0 million.

     On December 6, 2007, we sold 3,000,000 shares of our common stock in an underwritten public offering.

     Our 2008 capital investment budget for properties we owned at February 1, 2008 is estimated to be approximately $127.2 million, which includes $18.4 million for the purchase of leasehold and seismic in our areas of activity. The budget will be funded from our estimated operating cash flows and our bank borrowings. If our cash flows and bank borrowings are not sufficient to fund all of our estimated capital expenditures, we may fund any shortfall with proceeds from the sale of our debt or equity securities, reduce our capital budget or effect a combination of these alternatives. The amount and timing of our expenditures are subject to change based upon market conditions, results of expenditures, new opportunities and other factors.

Proved Reserves as of December 31, 2007

     Cawley Gillespie & Associates, Inc., our independent petroleum engineers, estimated the total proved reserves attributable to all of our oil and natural gas properties to be approximately 28.4 MMBbls of oil and approximately 57.2 Bcf of natural gas as of December 31, 2007.

     Approximately 75% of our proved reserves are oil and approximately 56% are categorized as proved developed reserves.

About Our Business and Strategy

     We have positioned our property portfolio on premier acreage in established geologic trends where we use our engineering, operational, financial and technical expertise to provide consistent long-term production and attractive returns on our investments. We prefer obtaining positions in long-lived oil and natural gas reserves to properties that have shorter reserve lives. We manage financial, reservoir, drilling and geological risks by emphasizing lower-risk acquisition, exploitation, enhancement and development drilling opportunities over higher-risk exploration projects. Furthermore, aggressive application of advanced technologies and production techniques, such as horizontal drilling and multi-stage fracture stimulation techniques have allowed us to achieve what we believe to be best-in-class productivity in our Barnett Shale natural gas resource play.

     Our experienced executive management team, together with our technical staff, has significantly grown our asset base, accumulating large acreage positions and working interests in high-quality oil and natural gas properties that demonstrate attractive returns on investment. From 2001 to 2007, we have replaced approximately 456% of our production. For the year ended December 31, 2007, our depletion per BOE was $13.02, and our related lifting costs, excluding production taxes, were $9.70 per BOE. Our long-lived Permian Basin reserves demonstrate shallow decline profiles, high margins, low replacement costs and consistent positive cash flows. We continue to utilize this reliable stream of cash flows from our oil production to support the development of our natural gas resource plays. We believe we are positioned in some of the most attractive areas of both the Barnett Shale and Wolfcamp Carbonate plays, and we have experienced a 95% drilling success rate in these projects as of December 31, 2007. Chesapeake Energy Corporation, or Chesapeake, as the operator of the majority of our interests in the Barnett Shale,

(2)

provides substantial operating expertise in the development of this project. We believe through the development of our existing core oil and gas properties we have significant growth potential.

     Approximately 90% of our proved undeveloped reserves are assigned to our Permian Basin long-lived oil properties and 10% are assigned to our two emerging resource gas projects. As of December 31, 2007, our standardized measure of discounted future net cash flows was $634.4 million. The following table presents proved reserves as of December 31, 2007 by our areas of operation.

	Proved Reserves as of December 31, 2007(1)
	Oil		Natural Gas		Total		% of Total
	(MBbl)		(MMcf)		(MBoe)		MBoe
Resource projects:
Barnett Shale		—		17,714		2,952		8	%
New Mexico Wolfcamp		1		24,284		4,048		10	%
Total resource projects		1		41,998		7,000		18	%
Permian Basin of West Texas		28,332		12,365		30,393		80	%
Onshore Gulf Coast of South Texas		101		2,871		580		2	%
Total		28,434		57,234		37,973		100	%

(1) Period end market pricing, as of December 31, 2007, was $96.01 per Bbl and $7.46 per MMBtu.

     In 2007, we spent $154.3 million on oil and natural gas related capital expenditures, and our 2008 capital budget is $127.2 million. We have primarily focused our efforts on achieving substantial growth in our production and proved reserves including our growth gas resource plays in the North Texas Barnett Shale and New Mexico Wolfcamp Carbonate regions. In 2008, we plan to drill over 108 gross infill wells, extension wells or well deepenings and to perform approximately 67 gross well workovers, refracs or restimulations. We plan to allocate our $127.2 million capital budget for 2008 as follows:

• $60.0 million for the drilling and completion of new wells and the acquisition of additional leasehold acreage in our North Texas Barnett Shale project;

• $40.0 million for the drilling and completion of new wells, pipeline construction, seismic and leasehold acquisitions in our New Mexico Wolfcamp Carbonate project;

• $24.5 million for the drilling and completion of new wells, refracs, restimulations, well deepenings and waterflood implementation in our Permian Basin of West Texas project; and

• $2.7 million for the drilling and completion of new wells in our Yegua/Frio, Utah/Colorado and Cotton Valley Reef projects.

Our Strategy

     Conduct Exploitation Activities on Our Existing Assets. We seek to maximize economic return on our existing assets by maximizing production rates and ultimate recovery, while managing operational efficiency to minimize direct lifting costs. For the year ended December 31, 2007, our lease operating expense per BOE produced was approximately $9.70, excluding production taxes. Development and production growth activities include infill and extension drilling of new wells, re-completion, pay adds and re-stimulation of existing wells and implementation and management of enhanced oil recovery projects such as waterflood operations. Operational efficiencies and cost reduction measures include optimization of surface facilities, such as fluid handling systems, gas compression or artificial lift installations. Efficiencies are also increased through aggressive monitoring and management of electrical power consumption, injection water quality programs, chemical and corrosion prevention programs and the use of production surveillance equipment and software. In all instances, a proactive approach is taken to achieve the desired result while ensuring minimal environmental impact.

     Accelerate Horizontal Drilling and Fracture Stimulation Activities in Gas Resource Plays. We believe the use of horizontal drilling and fracture stimulations has enabled us to develop reserves economically. The successful application of these technologies has increased net production in these resource plays from inception in July 2004 in the Wolfcamp to 9,306 Mcf per day and from inception in August 2005 in the Barnett Shale to 10,068 Mcf per day

(3)

during the quarter ended December 31, 2007. Based on this success, we plan to continue our activities in these two plays in 2008. Our current budget calls for the drilling and completing of 53 gross (20.0 net) wells in the Barnett Shale and the drilling and completing of 18 gross (15.3 net) wells in the Wolfcamp Carbonate. In addition to the drilling of these new wells, we intend to invest $19.9 million for leasehold, pipeline, gathering, seismic, and other infrastructure in these plays.

     Use Advanced Technologies and Production Techniques. We believe that 3-D seismic surveys, horizontal drilling, fracture stimulation and other advanced technologies and production techniques are useful tools that help improve normal drilling operations and enhance our production and returns. We believe that our use of these technologies and production techniques in exploring for, developing and exploiting oil and natural gas properties can: reduce drilling risks, lower finding costs, provide for more efficient production of oil and natural gas from our properties and increase the probability of locating and producing reserves that might not otherwise be discovered.

     Acquire Long-Lived Properties with Enhancement Opportunities. Our acquisition strategy is focused on leveraging our geographical expertise in our core areas of operation and seeking assets located in and around these areas. We selectively evaluate acquisition opportunities and expect that they will continue to play a role in increasing our reserve base and future drilling inventory. When identifying target assets, we focus primarily on reserve quality and assets in new developing plays with upside potential. Through this approach, we have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit properties without taking on significant integration risk.

     Conduct Exploratory Activities. Although we do not emphasize exploratory drilling, we will selectively undertake exploratory projects that have known geological and reservoir characteristics are in close proximity to existing wells so data from the existing wells can be correlated with seismic data on or near the prospect being evaluated, and that could have a potentially meaningful impact on our reserves.

Drilling Activities in 2007

     The following table shows our gross and net wells drilled, by geographic area, during 2007 and the number of wells in process at December 31, 2007.

					Number of Wells
			Number of		Drilling or		Gross
	Depth		Gross		Waiting on Completion		Productive		Gross
Area	Range (feet)		Wells Drilled		at December 31, 2007		Wells		Dry Wells
North Texas
Barnett Shale		7,000 — 8,000		52		17		34		1
Permian Basin of West Texas and New Mexico
Carm-Ann/Means		4,000 — 4,500		2		—		2		—
Harris		4,000 — 4,500		9		—		9		—
Fullerton		4,000 — 5,000		5		—		5		—
Wolfcamp Gas		4,300 — 4,500		34		1		32		1
Onshore Gulf Coast of Texas
Frio/Yegua/Wilcox		5,000 — 10,000		3		—		3		—
				105		18		85		2

(4)

Drilling and Acquisition Costs

     The table below shows our oil and natural gas property acquisition, exploration and development costs for the periods indicated.

	Year Ended December 31,
	2007		2006		2005
			($ in thousands)
Proved property acquisition costs	$	—		$  27,370	$	23,763
Unproved property acquisition costs		36,750		30,058		11,743
Exploration costs		55,827		71,003		15,455
Development costs		61,766		69,285		26,640
	$	154,343		$197,716	$	77,601

Current Drilling Projects

     Summarized below are our more significant current projects, including our capital budget for these projects in 2008:

     Resource Natural Gas Projects

     We have two resource natural gas projects in varying stages of development. They are the Barnett Shale gas project in the Fort Worth Basin of north Texas and the Wolfcamp gas project in the Permian Basin of New Mexico.

     We have budgeted approximately $100.0 million for these two resource natural gas projects in 2008 for the drilling and completion of approximately 71 new gross wells, leasehold acquisition, pipeline construction and pipeline compression.

     Fort Worth Basin of North Texas and Permian Basin of New Mexico

• Barnett Shale Gas Project, Tarrant County, Texas

     We have budgeted approximately $60.0 million for this project in 2008 for the drilling and completion of 53 new gross (20.0 net) wells, pipeline construction and leasehold acquisition. As of February 1, 2008, there were 3 drilling rigs running and 15 wells awaiting completion and pipeline connection in the Barnett Shale gas project.

• Wolfcamp Gas Project, Eddy and Chavez Counties, New Mexico —

     Our New Mexico Wolfcamp gas project consists of three areas of mutual interest in which the primary target is the Wolfcamp formation at a depth of approximately 4,500 feet. We anticipate participating in the drilling of approximately 18 gross (15.3 net) operated horizontal wells in New Mexico during 2008 in the Northern Area. We have budgeted approximately $40.0 million for this project in 2008 to fund the drilling in the Northern Area, the installation of pipelines and related infrastructure, the acquisition of additional leasehold, and the acquisition of 3-D seismic data in the Southern Area. As of February 1, 2008, 1 drilling rig was running, 2 wells were in the process of completion and 1 well was awaiting completion.

     Permian Basin of West Texas

     Our significant producing properties in the Permian Basin of west Texas are described below.

• Fullerton San Andres Field, Andrews County, Texas

     We have budgeted approximately $4.0 million in 2008 to fund the drilling of an estimated 7 gross (6.2 net) new wells and the conversion to injection of 2 gross (1.6 net) existing wells. Our average working interest in the Fullerton properties is approximately 85%.

(5)

• Carm-Ann San Andres Field / N. Means Queen Unit, Andrews & Gaines Counties, Texas

     We have budgeted approximately $3.3 million for the Carm-Ann/N. Means Queen properties in 2008 for the drilling and completion of 5 gross (4.3 net) wells and the conversion to injection of 6 gross (5.1 net) existing wells. Our average working interest in these properties is approximately 77%.

• Harris San Andres Field, Andrews and Gaines Counties, Texas

     We have budgeted approximately $5.3 million for the Harris San Andres properties in 2008 for the drilling of an estimated 7 gross (6.3 net) wells and the re-frac workover or conversion to injection of 16 gross (14.4 net) existing wells. Our average working interest in these properties is approximately 90%.

• Diamond M Canyon Reef Unit, Scurry County, Texas

     A total of $9.6 million has been budgeted in 2008 for the Diamond M Canyon Reef project for the drilling and completion of approximately 12 gross (7.9 net) new wells and the workover or deepening of approximately 18 gross (11.8 net) existing wells. Our average working interest in these properties is approximately 66% with our work-to-earn arrangement with Southwestern Energy Company.

• Diamond M Shallow leases, Scurry County, Texas

     A total of $1.3 million has been budgeted in 2008 for the Diamond M Shallow project for the installation of dual injection strings in approximately 25 gross (16.5 net) existing wells. Our average working interest in these properties is approximately 66% with our work-to-earn arrangement with Southwestern Energy Company.

     Onshore Gulf Coast of South Texas

• Yegua/Frio/Wilcox and Cook Mountain Gas Projects, Jackson, Wharton and Liberty Counties, Texas

     We have budgeted approximately $0.7 million for the south Texas projects in 2008 for the drilling and completion of 2 gross (0.5 net) wells.

     Other Projects

• Utah/Colorado Conventional Oil & Gas and Heavy Oil Sands Projects, Uinta Basin

     We have budgeted approximately $1.5 million for the Utah/Colorado project in 2008 for the drilling and completion of 3 gross (2.9 net) wells and the acquisition of additional leasehold. We own and operate 97.5% of this project.

Oil and Natural Gas Prices

     The average wellhead prices we received for the oil and natural gas we produced in 2007, 2006 and 2005 are shown in the table below.

	Average Price Received for the
	Year Ended December 31,
	2007		2006		2005
Oil (Bbl)	$	65.97	$	59.86	$	51.78
Natural gas (Mcf)	$	6.29	$	6.19	$	8.54

     The average price we received for our oil sales at February 1, 2008 was approximately $85.17 per Bbl. At the same date, the average price we were receiving for our natural gas was approximately $6.91 per Mcf.

(6)

     There is substantial uncertainty regarding future oil and natural gas prices and we can provide no assurance that prices will remain at current levels. We have entered into derivative contracts in an attempt to reduce the risk of fluctuating oil and natural gas prices.

Employees and Consultants

     At February 1, 2008, we had 43 full time employees. We also retain independent land, geological, geophysical, engineering, drilling and financial consultants from time to time and expect to continue to do so in the future. Additionally, we retain contract pumpers on a month-to-month basis.

     Until his retirement on June 26, 2007, Thomas R. Cambridge, our former Chairman of the Board of Directors, served in the capacity of a geological consultant and not as a full-time employee.

     We consider our employee relations to be satisfactory. None of our employees are represented by a union and we have not experienced work stoppages or strikes.

Wells Drilled

     The following table shows certain information concerning the number of gross and net wells we drilled during the three-year period ended December 31, 2007.

	Exploratory Wells (1)								Development Wells (2)
Year Ended	Productive				Dry				Productive				Dry
December 31,	Gross		Net		Gross		Net		Gross		Net		Gross		Net
2007		36.0		13.93		1.0		1.00		67.0		32.3		1.00		0.37
2006		5.0		2.87		3.0		1.42		122.0		68.4		1.00		0.08
2005		21.0		5.32		6.0		0.64		48.0		27.5		—		—

(1)	An exploratory well is a well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.
(2)	A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

     All of our drilling is performed on a contract basis by third-party drilling contractors. We do not own any drilling equipment. We maintain a limited number of supervisory and field personnel to oversee drilling and production operations. Our plans to drill additional wells are determined in part by the anticipated availability of acceptable drilling equipment and crews. We do not currently have any contractual commitments that ensure we will have adequate drilling equipment or crews to achieve our drilling plans. As of February 1, 2008, we had 3 drilling rigs in operation at our Barnett Shale project and 1 drilling rig in operation at our New Mexico project. We believe that we currently can secure commitments from drilling companies that will make equipment available to us for drilling wells on our operated projects. In the case of our non-operated properties, we also believe that the operators of these other properties will be able to secure equipment for drilling on our non-operated properties. However, we can provide no assurance that our expectations regarding the availability of drilling equipment from these companies will be met.

     At February 1, 2008, we were participating in the completion of 10 gross (4.69 net) wells, 6 gross (1.92 net) wells were awaiting completion, 2 gross (0.66 net) wells were shut-in waiting on pipelines and 4 gross (1.47 net) wells were in process of drilling.

(7)

Volumes, Prices and Lifting Costs

     The following table shows certain information about our oil and natural gas production volumes, average sales prices per Mcf of natural gas and Bbl of oil and the average lifting (production) cost per BOE for the three-year period ended December 31, 2007.

	Year Ended December 31,
	2007		2006		2005
	(in thousands, except per unit data)
Production, Prices and Lifting Costs:
Oil (Bbls)		1,051		1,137		923
Natural gas (Mcf)		7,422		6,539		3,592
BOE		2,288		2,227		1,522
Oil price (per Bbl) (1)	$	65.97	$	59.86	$	51.78
Natural gas price (per Mcf) (1)	$	6.29	$	6.19	$	8.54
BOE price (1)	$	50.72	$	48.73	$	51.57
Average Lifting Cost (including production taxes) per BOE	$	11.60	$	10.06	$	9.24

(1) Average price received at the wellhead for our oil and natural gas.

     In 2007, approximately 46% of the volume of our production was oil and 54% was natural gas. The majority of the oil production is from our Permian Basin longer-lived oil assets. The majority of the natural gas production is from our Barnett Shale and New Mexico Wolfcamp assets.

     The following table summarizes our revenues by product sold for each year in the three year period ended December 31, 2007.

	2007		2006			2005
			($ in thousands)
Oil revenue	$	69,315		$68,076		$	47,800
Effect of oil hedges		—		(11,512	)		(12,139	)
Natural gas revenue		46,716		40,461			30,690
Effect of natural gas hedges		—		—			(201	)
	$	116,031		$97,025		$	66,150

     Our oil sales in 2007 represented approximately 60% of our combined oil and natural gas revenues (not considering the effect of hedging) for the year ended December 31, 2007, as compared to 63% in 2006, and 61% in 2005.

Markets and Customers

     Our oil and natural gas production is sold at the well site on an as produced basis at market-related prices in the areas where the producing properties are located. We do not refine or process any of the oil or natural gas we produce and all of our production is sold to unaffiliated purchasers on a month-to-month basis.

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     In the table below, we show the purchasers that accounted for 10% or more of our revenues during the specified years.

	2007			2006			2005
Allegro Investments, Inc.		(1	)		(1	)		14	%
Conoco, Inc.		21	%		20	%		12	%
Texland Petroleum, Inc.		30	%		30	%		40	%
Tri-C Resources, Inc.		(1	)		12	%		(1	)
Dale Operating Company		(1	)		10	%		(1	)
Chesapeake Operating, Inc.		12	%		(1	)		(1	)

(1) Less than 10%.

     We do not believe the loss of any one of our purchasers would materially affect our ability to sell the oil and natural gas we produce. Other purchasers are available in our areas of operations.

     Our future ability to market our oil and natural gas production depends upon the availability and capacity of natural gas gathering systems and pipelines and other transportation facilities. We are not obligated to provide a fixed or determinable quantity of oil and natural gas under any existing arrangements or contracts.

     Our business does not require us to maintain a backlog of products, customer orders or inventory.

Office Facilities

     Our principal executive offices are located in Midland, Texas, where we lease approximately 22,200 square feet of office space at 1004 North Big Spring, Suite 400, Midland, Texas 79701. Our current rental rate is $16,650 per month. The lease expires on February 28, 2010.

     We have three field offices and storage facilities. These three offices are located in Andrews and Snyder, Texas and Hagerman, New Mexico. The current monthly rental rate is $1,200 for the Snyder office. The Snyder office lease expires upon the cessation of production from the Diamond “M” area wells.

Competition

     The oil and natural gas industry is highly competitive, particularly in the areas of acquiring exploratory and development prospects and producing properties. The principal means of competing for the acquisition of oil and natural gas properties are the amount and terms of the consideration offered. Our competitors include major oil companies, independent oil and natural gas firms and individual producers and operators. Many of our competitors have financial resources, staffs and facilities much larger than ours.

     We are also affected by competition for drilling rigs and the availability of related equipment. With relatively high oil and natural gas prices, the oil and natural gas industry typically experiences shortages of drilling rigs, equipment, pipe and qualified field personnel. Although we are unable to predict when or to what extent our exploration and development activities will be affected by rig, equipment or personnel shortages, we have recently experienced, and continue to experience, delays in some of our planned activities and operations because of these shortages.

     Intense competition among independent oil and natural gas producers requires us to react quickly to available exploration and acquisition opportunities. We try to position for these opportunities by maintaining:

• adequate capital resources for projects in our core areas of operations;

• the technological capabilities to conduct a thorough evaluation of a particular project; and

• a small staff that can respond quickly to exploration and acquisition opportunities.

     The principal resources we need for acquiring, exploring, developing, producing and selling oil and natural gas are:

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• leasehold prospects under which oil and natural gas reserves may be discovered or developed;

• drilling rigs and related equipment to explore for such reserves; and

• knowledgeable and experienced personnel to conduct all phases of oil and natural gas operations.

Oil and Natural Gas Regulations

     Our operations are regulated by certain federal and state agencies. Oil and natural gas production and related operations are or have been subject to:

• price controls;

• taxes; and

• environmental and other laws relating to the oil and natural gas industry.

     We cannot predict how existing laws and regulations may be interpreted by governmental agencies or court rulings, whether additional laws and regulations will be adopted, or the effect such interpretations or new laws and regulations may have on our business, financial condition or results of operations.

     Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations that are enforced by federal, state and local governmental agencies. Failure to comply with these rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are frequently amended or reinterpreted, we are not able to predict the future cost or impact of compliance with these laws.

     Texas and many other states require drilling permits, bonds and operating reports. Other requirements relating to the exploration and production of oil and natural gas are also imposed. These states also have statutes or regulations addressing conservation matters, including provisions for:

• the unitization of pooling of oil and natural gas properties;

• the establishment of maximum rates of production from oil and natural gas wells; and

• the regulation of spacing, plugging and abandonment of wells.

     Sales of natural gas we produce are not regulated and are made at market prices. However, the Federal Energy Regulatory Commission (FERC) regulates interstate and certain intrastate natural gas transportation rates and services conditions, which affect the marketing of our natural gas, as well as the revenues we receive for sales of our production. Since the mid-1980s, FERC has issued a series of orders, culminating in Order Nos. 636, 636-A, 636-B, and 636-C. These orders, commonly known as Order 636, have significantly altered the marketing and transportation service, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services these pipelines previously performed.

     One of FERC’s purposes in issuing the orders was to increase competition in all phases of the natural gas industry. Order 636 and subsequent FERC orders issued in individual pipeline restructuring proceedings has been the subject of appeals, the results of which have generally been supportive of the FERC’s open-access policy. In 1996, the United States Court of Appeals for the District of Columbia Circuit largely upheld Order No. 636. Because further review of certain of these orders is still possible, and other appeals remain pending, it is difficult to predict the ultimate impact of the orders on Parallel and our natural gas marketing efforts. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets. While significant regulatory uncertainty remains, Order 636 may ultimately enhance our ability to market and transport our natural gas, although it may also subject us to greater competition.

     Sales of oil we produce are not regulated and are made at market prices. The price we receive from the sale of oil is affected by the cost of transporting the product to market. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for interstate common carrier oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. These regulations

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could increase the cost of transporting oil by interstate pipelines, although the most recent adjustment generally decreased rates. These regulations have generally been approved on judicial review. We are unable to predict with certainty what effect, if any, these regulations will have on us. The regulations may, over time, tend to increase transportation costs or reduce wellhead prices for oil.

     We are also required to comply with various federal and state regulations regarding plugging and abandonment of oil and natural gas wells.

Environmental Regulations

     Various federal, state and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment, health and safety, affect our operations and costs. These laws and regulations sometimes:

• require prior governmental authorization for certain activities;

• limit or prohibit activities because of protected areas or species;

• impose substantial liabilities for pollution related to our operations or properties; and

• provide significant penalties for noncompliance.

     In particular, our exploration and production operations, our activities in connection with storing and transporting oil and other liquid hydrocarbons, and our use of facilities for treating, processing or otherwise handling hydrocarbons and related exploration and production wastes are subject to stringent environmental regulations. As with the industry generally, compliance with existing and anticipated regulations increases our overall cost of business. While these regulations affect our capital expenditures and earnings, we believe that they do not affect our competitive position in the industry because our competitors are also affected by the same environmental regulatory programs. Since environmental regulations have historically been subject to frequent change, we cannot predict with certainty the future costs or other future impacts of environmental regulations on our future operations. A discharge of hydrocarbons or hazardous substances into the environment could subject us to substantial expense, including the cost to comply with applicable regulations that require a response to the discharge, such as claims by neighboring landowners, regulatory agencies or other third parties for costs of:

• containment or cleanup;

• personal injury;

• property damage; and

• penalties assessed or other claims sought for natural resource damages.

     The following are examples of some environmental laws that potentially impact our operations.

•

Water. The Oil Pollution Act, or OPA, was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972 (FWPCA) and other statutes as they pertain to prevention of and response to major oil spills. The OPA subjects owners of facilities to strict, joint and potentially unlimited liability for removal costs and certain other consequences of an oil spill, where such spill is into navigable waters, or along shorelines. In the event of an oil spill into such waters, substantial liabilities could be imposed upon us. States in which we operate have also enacted similar laws. Regulations are currently being developed under the OPA and similar state laws that may also impose additional regulatory burdens on us.

The FWPCA imposes restrictions and strict controls regarding the discharge of produced waters, other oil and gas wastes, any form of pollutant, and, in some instances, storm water runoff, into waters of the United States. The FWPCA provides for civil, criminal and administrative penalties for any unauthorized discharges and, along with the OPA, imposes substantial potential liability for the costs of removal, remediation or damages resulting from an unauthorized discharge. State laws for the control of water pollution also provide civil, criminal and administrative penalties and liabilities in the case of an unauthorized discharge into state waters. The cost of compliance with the OPA and the FWPCA have

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	not historically been material to our operations, but there can be no assurance that changes in federal, state or local water pollution control programs will not materially adversely affect us in the future. Although no assurances can be given, we believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations.
•	Solid Waste. We generate non-hazardous solid waste that fall under the requirements of the Federal Resource Conservation and Recovery Act and comparable state statues. The EPA and the states in which we operate are considering the adoption of stricter disposal standards for the type of non-hazardous waste we generate. The Resource Conservation and Recovery Act also governs the generation, management, and disposal of hazardous wastes. At present, we are not required to comply with a substantial portion of the Resource Conservation and Recovery Act requirements because our operations generate minimal quantities of hazardous wastes. However, it is anticipated that additional wastes, which could include wastes currently generated during operations, could in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly disposal and management requirements than are non-hazardous wastes. Such changes in the regulations may result in us incurring additional capital expenditures or operating expenses.
•	Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act, sometimes called CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons in connection with the release of a hazardous substance into the environment. These persons include the current owner or operator of any site where a release historically occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In the course of our ordinary operations, we may have managed substances that may fall within CERCLA’s definition of a hazardous substance. We may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites where we disposed of or arranged for the disposal of these substances. This potential liability extends to properties that we owned or operated as well as to properties owned and operated by others at which disposal of our hazardous substances occurred.
	We currently own or lease numerous properties that for many years have been used for exploring and producing oil and natural gas. Although we believe we use operating and disposal practices standard in the industry, hydrocarbons or other wastes may have been disposed of or released by us on or under properties that we have owned or leased. In addition, many of these properties have been previously owned or operated by third parties who may have disposed of or released hydrocarbons or other wastes at these properties. Under CERCLA, and analogous state laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by prior owners or operators, to clean up contaminated property, including contaminated groundwater, or to perform remedial plugging operations to prevent future contamination.

     Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of fossil fuels, are examples of greenhouse gases. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least nine states in the Northeast and five states in the West including New Mexico have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases, 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 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. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of regulations by the EPA or 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.

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ITEM 1A. RISK FACTORS

     The following should be considered carefully with the information provided elsewhere in this Annual Report on Form 10-K in reaching a decision regarding an investment in our securities.

Risks Related to Our Business

The volatility of the oil and natural gas industry may have an adverse impact on our operations.

     Our revenues, cash flows and profitability are substantially dependent upon prevailing prices for oil and natural gas. In recent years, oil and natural gas prices and, therefore, the level of drilling, exploration, development and production, have been extremely volatile. Any significant or extended decline in oil or natural gas prices will have a material adverse effect on our business, financial condition and results of operations and could impair access to future sources of capital. Volatility in the oil and natural gas industry results from numerous factors, over which we have no control, including:

•	the level of oil and natural gas prices, expectations about future oil and natural gas prices and the ability of international cartels to set and maintain production levels and prices;
•	the cost of exploring for, producing and transporting oil and natural gas;
•	the level and price of foreign oil and natural gas transportation;
•	available pipeline and other oil and natural gas transportation capacity;
•	weather conditions;
•	international political, military, regulatory and economic conditions;
•	the level of consumer demand;
•	the price and the availability of alternative fuels;
•	the effect of worldwide energy conservation measures; and
•	the ability of oil and natural gas companies to raise capital.
Significant declines in oil and natural gas prices for an extended period may:
•	impair our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;
•	reduce the amount of oil and natural gas that we can produce economically;
•	cause us to delay or postpone some of our capital projects;
•	reduce our revenues, operating income and cash flow; and
•	reduce the recorded value of our oil and natural gas properties.

     No assurance can be given that current levels of oil and natural gas prices will continue. We expect oil and natural gas prices, as well as the oil and natural gas industry generally, to continue to be volatile.

We must replace oil and natural gas reserves that we produce. Failure to replace reserves may negatively affect our business.

     Our future performance depends in part upon our ability to find, develop and acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves decline as they are depleted and we must locate and develop or acquire new oil and natural gas reserves to replace reserves being depleted by production. No assurance can be given that we will be able to find and develop or acquire additional reserves on an economic basis. If we cannot economically replace our reserves, our results of operations may be materially adversely

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affected and our stock price may decline and the price at which a note holder would be able to sell our 10¹/4% senior notes could decline.

We are subject to uncertainties in reserve estimates and future net cash flows.

     There is substantial uncertainty in estimating quantities of proved reserves and projecting future production rates and the timing of development expenditures. No one can measure underground accumulations of oil and natural gas in an exact way. Accordingly, oil and natural gas reserve engineering requires subjective estimations of those accumulations. Estimates of other engineers might differ widely from those of our independent petroleum engineers, and our independent petroleum engineers may make material changes to reserve estimates based on the results of actual drilling, testing, and production. As a result, our reserve estimates often differ from the quantities of oil and natural gas we ultimately recover. Also, we make certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Some of our reserve estimates are made without the benefit of a lengthy production history and are calculated using volumetric analysis. Those estimates are less reliable than estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay and an estimation of the productive area.

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

• actual prices we receive for oil and natural gas;

• the amount and timing of actual production;

• supply and demand of oil and natural gas;

• limits of increases in consumption by natural gas purchasers; and

• changes in governmental regulations or taxation.

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

Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do.

     We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation, exploration and production. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies in each of the following areas:

• seeking to acquire desirable producing properties or new leases for future exploration;

• marketing our oil and natural gas production;

• integrating new technologies; and

• seeking to acquire the equipment and expertise necessary to develop and operate our properties.

     Many of our competitors have financial, technological and other resources substantially greater than ours, and some of them are fully integrated oil and natural gas companies. These companies may be able to pay more for

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development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

We do not control all of our operations and development projects, which may adversely affect our production, revenues and results of operations.

     Substantially all of our business activities are conducted through joint operating agreements under which we own partial interests in oil and natural gas wells. As of December 31, 2007, we owned interests in 369 gross (306.55 net) oil and natural gas wells for which we were the operator and 569 gross (270.84 net) oil and natural gas wells where we were not the operator. Included in these wells are 175 gross (79.07 net) wells which are shut in or temporarily abandoned and 128 gross (98.30 net) injection wells. Furthermore, we are not the operator of any of our interests in the Barnett Shale project. As a result, the success and timing of our drilling and development activities on properties operated by others depends upon a number of factors outside of our control, including the operator’s:

• timing and amount of capital expenditures;

• expertise and financial resources;

• inclusion of other participants in drilling wells; and

• use of technology.

     Further, we may not be in a position to remove the operator in the event of poor performance, and we may not have control over normal operating procedures, expenditures or future development of underlying properties. If drilling and development activities are not conducted on these properties or are not conducted on a timely basis, we may be unable to increase our production or offset normal production declines, which may adversely affect our production, revenues and results of operations.

Our business is subject to many inherent risks, including operating risks, which may result in substantial losses, and insurance may be unavailable or inadequate to protect us against these risks.

     Oil and natural gas drilling activities and production operations are highly speculative and involve a high degree of risk. These operations are marked by unprofitable efforts because of dry holes and wells that do not produce oil or natural gas in sufficient quantities to return a profit. The success of our operations depends, in part, upon the ability of our management and technical personnel. The cost of drilling, completing and operating wells is often uncertain. There is no assurance that our oil and natural gas drilling or acquisition activities will be successful, that any production will be obtained, or that any such production, if obtained, will be profitable.

     Our operations are subject to all of the operating hazards and risks normally incident to drilling for and producing oil and natural gas. These hazards and risks include, but are not limited to:

• explosions, blowouts and fires;

• natural disasters;

• pressure forcing oil or natural gas out of the wellbore at a dangerous velocity coupled with the potential for fire or explosion;

• weather;

• failure of oilfield drilling and service equipment and tools;

• changes in underground pressure in a formation that causes the surface to collapse or crater;

• pipeline ruptures or cement failures;

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• environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases; and

• availability of needed equipment at acceptable prices, including steel tubular products.

     Any of these risks can cause substantial losses resulting from:

• injury or loss of life;

• damage to and destruction of property, natural resources and equipment;

• pollution and other environmental damage;

• regulatory investigations and penalties;

• suspension of our operations; and

• repair and remediation costs.

     As is customary in the industry, we maintain insurance against some, but not all, of these hazards. We maintain general liability insurance and obtain Operator’s Extra Expense insurance on a well-by-well basis. We carry insurance against certain pollution hazards, subject to our insurance policy’s terms, conditions and exclusions. If we sustain an uninsured loss or liability, our ability to operate could be materially adversely affected.

     Our oil and natural gas operations are not subject to renegotiation of profits or termination of contracts at the election of the federal government.

The oil and natural gas industry is capital intensive.

     The oil and natural gas industry is capital intensive. We make substantial capital expenditures for the acquisition, exploration for and development of oil and natural gas reserves.

     Historically, we have financed capital expenditures primarily with cash generated by operations, proceeds from borrowings and sales of our equity securities. In addition, we have sold and may consider selling additional assets to raise additional operating capital. From time to time, we may also reduce our ownership interests in our projects in order to reduce our capital expenditure requirements.

     Our cash flow from operations and access to capital is subject to a number of variables, including:

• our proved reserves;

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

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

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

     Any one of these variables can materially affect our ability to borrow under our revolving credit facility.

     If our revenues or the borrowing base under our revolving credit facility 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 undertake or complete future drilling projects. We may, from time to time, seek additional financing, either in the form of increased bank borrowings, sale of debt or equity securities or other forms of financing and there can be no assurance as to the availability of any additional financing upon terms acceptable to us.

There are risks in acquiring producing properties, including difficulties in integrating acquired properties into our business, additional liabilities and expenses associated with acquired properties, diversion of management attention, increasing the scope, geographic diversity and complexity of our operations and incurrence of additional debt.

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     Our business strategy includes growing our reserve base through acquisitions. Our failure to integrate acquired businesses successfully into our existing business, or the expense incurred in consummating future acquisitions, could result in unanticipated expenses and losses. In addition, we may assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

     We are continually investigating opportunities for acquisitions. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Our ability to make future acquisitions may be constrained by our ability to obtain additional financing.

     Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expense, all of which could have a material adverse effect on our financial condition and operating results.

We could experience delays in securing drilling equipment and crews, which would cause us to fail to meet our drilling plans and negatively impact our operations.

     We utilize drilling contractors to perform all of the drilling on our projects. We maintain a limited number of supervisory and field personnel to oversee drilling and production operations. Our plans to drill additional wells are determined in large part by the anticipated availability of acceptable drilling equipment and crews. We do not currently have any contractual commitments that ensure we will have adequate drilling equipment or crews to achieve our drilling plans. If our anticipated levels of drilling equipment are not made available to us, we will have to modify our drilling plans, which would cause us to fail to meet our drilling plans and negatively impact our operations. If we cannot meet our drilling plans, the value of your investment in us may decline.

The marketability of our natural gas production depends on facilities that we typically do not own or control.

     The marketability of our natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We generally deliver natural gas through natural gas gathering systems and natural gas pipelines that we do not own. Our ability to produce and market natural gas on a commercial basis could be harmed by any significant change in the cost or availability of such systems and pipelines.

Our producing properties are geographically concentrated.

     A substantial portion of our proved oil and natural gas reserves are located in the Permian Basin of West Texas and Eastern New Mexico. Specifically, as of December 31, 2007, approximately 93.5% of the present value of our estimated future net revenues from our proved reserves relates to our proved reserves located in the Permian Basin. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells due to mechanical problems, damages to the current producing reservoirs, significant governmental regulation, including any curtailment of production, or interruption of transportation of oil or natural gas produced from the wells.

Our derivative activities create a risk of financial loss.

     In order to manage our exposure to price risks in the marketing of our oil and natural gas, we have in the past and expect to continue to enter into oil and natural gas price risk management arrangements with respect to a portion of our expected production. We use derivative arrangements such as swaps, puts and collars that generally result in a fixed price or a range of minimum and maximum price limits over a specified time period. Certain derivative contracts may limit the benefits we could realize if actual prices received are above the contract price. In a typical derivative transaction utilizing a swap arrangement, we will have the right to receive from the counterparty the excess of the fixed price specified in the contract over a floating price based on a market index, multiplied by the quantity identified in the derivative contract. If the floating price exceeds the fixed price, we are required to pay the counterparty this difference multiplied by the quantity identified in the derivative contract. Derivative arrangements could prevent us from receiving the full advantage of increases in oil or natural gas prices above the fixed amount specified in the derivative contract. In addition, these transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

• the counterparties to our future contracts fail to perform under the contract; or

• a sudden, unexpected event materially impacts oil or natural gas prices.

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     In the past, some of our derivative contracts required us to deliver cash collateral or other assurances of performance to the counterparties in the event that our payment obligations exceeded certain levels. Future collateral requirements are uncertain but will depend on arrangements with our counterparties and highly volatile oil and natural gas prices.

     In addition, increases in oil and natural gas prices negatively affect the fair value of certain of our derivatives contracts as recorded in our balance sheet and, consequently, our reported net income. Changes in the recorded fair value of certain of our derivatives contracts are marked to market through earnings and the decrease in the fair value of these contracts during any period could result in significant charges to earnings. The increase in oil and natural gas prices, should it continue, will cause this negative effect on earnings to become more significant. We are currently unable to estimate the effects on earnings in future periods, but the effects could be significant.

We are subject to complex federal, state and local laws and regulations that could adversely affect our business.

     Extensive federal, state and local regulation of the oil and natural gas industry significantly affects our operations. In particular, our oil and natural gas exploration, development and production activities are subject to stringent environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil and natural gas wells and other related facilities. These regulations may become more demanding in the future. Matters subject to regulation include:

• permits for drilling operations;

• drilling bonds;

• spacing of wells;

• unitization and pooling of properties;

• environmental protection;

• reports concerning operations; and

• taxation.

     Under these laws and regulations, we could be liable for:

• personal injuries;

• property damage;

• oil spills;

• discharge of hazardous materials;

• reclamation costs;

• remediation and clean-up costs; and

• other environmental damages.

     Failure to comply with these laws and regulations also may result in the suspension or terminations of our operations and subject us to administrative, civil and criminal penalties. Further, these laws and regulations could change in ways that substantially increase our costs. Any of these liabilities, penalties, suspensions, terminations or regulatory changes could make it more expensive for us to conduct our business or cause us to limit or curtail some of our operations.

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Declining oil and natural gas prices may cause us to record ceiling test write-downs.

     We use the full cost method of accounting to account for our oil and natural gas operations. This means that we capitalize the costs to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the capitalized costs of oil and natural gas properties may not exceed a ceiling limit, which is based on the present value of estimated future net revenues, net of income tax effects, from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties. These rules generally require pricing future oil and natural gas production at unescalated oil and natural gas prices in effect at the end of each fiscal quarter, with effect given to cash flow hedge positions. If our capitalized costs of oil and natural gas properties, net of related deferred taxes, exceed the ceiling limit, we must charge the amount of the excess against earnings. This is called a ceiling test write-down. This non-cash impairment charge does not affect cash flow from operating activities, but it does reduce stockholders’ equity. Generally, impairment charges cannot be restored by subsequent increases in the prices of oil and natural gas.

     The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when oil and natural gas prices decline. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves.

     We did not recognize an impairment in 2007. We cannot assure you that we will not experience ceiling test write-downs in the future.

Terrorist activities may adversely affect our business.

     Terrorist activities, including events similar to those of September 11, 2001, or armed conflict involving the United States may adversely affect our business activities and financial condition. If events of this nature occur and persist, the resulting political and social instability could adversely affect prevailing oil and natural gas prices and cause a reduction in our revenues. In addition, oil and natural gas production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged. Costs associated with insurance and other security measures may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

We are highly dependent upon key personnel.

     Our success is highly dependent upon the services, efforts and abilities of key members of our management team. Our operations could be materially and adversely affected if one or more of these individuals become unavailable for any reason.

     We do not have employment agreements with any of our officers or other key employees. Without these agreements, our ability to obtain and retain qualified officers and employees may be adversely affected, especially in periods of improving market conditions.

     Our future growth and profitability will also be dependent upon our ability to attract and retain other qualified management personnel and to effectively manage our growth. There can be no assurance that we will be successful in doing so.

Part of our business is seasonal in nature.

     Weather conditions affect the demand for and price of oil and natural gas and can also delay drilling activities, temporarily disrupting our overall business plans. Demand for oil and natural gas is typically higher during winter months than summer months. However, warm winters can also lead to downward price trends. As a result, our results of operations may be adversely affected by seasonal conditions.

Failure to maintain effective internal controls could have a material adverse effect on our operations.

     Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to produce reliable financial reports. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial reports, our business decision process may be adversely affected, our business and operating results could be harmed, and investors could lose confidence in our reported financial information.

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Our business can be adversely impacted by downward changes in oil and natural gas prices, and most significantly by declines in oil prices.

     Our revenues, cash flows and profitability are substantially dependent on prevailing oil and natural gas prices, which are volatile. Declines in oil and natural gas prices would not only reduce revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. Further, oil and natural gas prices do not necessarily move in tandem. Because approximately 87.0% of our estimated future revenues from our proved reserves as of December 31, 2007 are from oil production, we will be more affected by movements in oil prices.

A shortage of available drilling rigs, equipment and personnel may delay or restrict our operations.

     The oil and natural gas industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or personnel. During these periods, the costs and delivery times of drilling rigs, equipment and supplies are substantially greater. In addition, demand for, and wage rates of, qualified drilling rig crews rise with increases in the number of active rigs in service. Shortages of drilling rigs, equipment, supplies or personnel may increase drilling costs or delay or restrict our exploration and development operations, all or any one of which could harm our business financial condition and results of operations.

Risks Relating to Our Common Stock

We do not pay dividends on our common stock.

     We have never paid dividends on our common stock, and do not intend to pay cash dividends on the common stock in the foreseeable future. Net income from our operations, if any, will be used for the development of our business, including capital expenditures and to retire debt. Any decisions to pay dividends on the common stock in the future will depend upon our profitability at the time, the available cash and other factors. Our ability to pay dividends on our common stock is further limited by the terms of our revolving credit facility and the Indenture governing our 10¹/4% senior notes

Our stockholders’ rights plan, provisions in our corporate governance documents and Delaware law may delay or prevent an acquisition of Parallel, which could decrease the value of our common stock.

     Our certificate of incorporation, our bylaws and the Delaware General Corporation Law contain provisions that may discourage other persons from initiating a tender offer or takeover attempt that a stockholder might consider to be in the best interest of all stockholders, including takeover attempts that might result in a premium to be paid over the market price of our stock.

     On October 5, 2000, our Board of Directors adopted a stockholder rights plan. The plan is designed to protect Parallel from unfair or coercive takeover attempts and to prevent a potential acquirer from gaining control of Parallel without fairly compensating all of the stockholders. The plan authorized 50,000 shares of $0.10 par Series A Preferred Stock Purchase Rights. A dividend of one Right for each share of our outstanding common stock was distributed to stockholders of record at the close of business on October 16, 2000. If a public announcement is made that a person has acquired 15% or more of our common stock, or a tender or exchange offer is made for 15% of more of the common stock, each Right entitles the holder to purchase from the company one one-thousandth of a share of Series A Preferred Stock, at an exercise price of $26.00 per one one-thousandth of a share, subject to adjustment. In addition, under certain circumstances, the rights entitle the holders to buy Parallel’s stock at a 50% discount. We are authorized to issue 10.0 million shares of preferred stock; there are no outstanding shares as of December 31, 2007. Our Board of Directors has total discretion in the issuance and the determination of the rights and privileges of any shares of preferred stock which might be issued in the future, which rights and privileges may be detrimental to the holders of the common stock. It is not possible to state the actual effect of the authorization and issuance of a new series of preferred stock upon the rights of holders of the common stock and other series of preferred stock unless and until the Board of Directors determines the attributes of any new series of preferred stock and the specific rights of its holders. These effects might include:

• restrictions on dividends on common stock and other series of preferred stock if dividends on any new series of preferred stock have not been paid;

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• dilution of the voting power of common stock and other series of preferred stock to the extent that a new series of preferred stock has voting rights, or to the extent that any new series of preferred stock is convertible into common stock;

• dilution of the equity interest of common stock and other series of preferred stock; and

• limitation on the right of holders of common stock and other series of preferred stock to share in Parallel’s assets upon liquidation until satisfaction of any liquidation preference attributable to any new series of preferred stock.

     The issuance of preferred stock in the future could discourage, delay or prevent a tender offer, proxy contest or other similar transaction involving a potential change in control of Parallel that might be viewed favorably by stockholders.

Future sales of our common stock could adversely affect our stock prices.

     Substantial sales of our common stock in the public market, or the perception by the market that those sales could occur, may lower our stock price or make it difficult for us to raise additional equity capital in the future. These potential sales could include sales of our common stock by our directors and officers, who beneficially owned approximately 3.35% of the outstanding shares of our common stock as of February 14, 2008.

The price of our common stock may fluctuate which may cause our common stock to trade at a substantially lower price than the price which you paid for our common stock.

     The trading price of our common stock and the price at which we may sell securities in the future is subject to substantial fluctuations in response to various factors, including any of the following: our ability to successfully accomplish our business strategy; the trading volume in our stock; changes in governmental regulations; actual or anticipated variations in our quarterly or annual financial results; our involvement in litigation; general market conditions; the prices of oil and natural gas; our ability to economically replace our reserves; announcements by us and our competitors; our liquidity; our ability to raise additional funds; and other events.

If securities analysts downgrade our stock or cease coverage of us, the price of our stock could decline.

     The trading market for our common stock relies in part on the research and reports that industry or financial analysts publish about us or our business. We do not control these analysts. Furthermore, there are many large, well-established, publicly traded companies active in our industry and market, which may mean that it is less likely that we will receive widespread analyst coverage. If one or more of the analysts who do cover us downgrade our stock, our stock price would likely decline rapidly. If one or more of these analysts cease coverage of our company, we could lose visibility in the market, which in turn could cause our stock price to decline.

Risks Relating to Our 10 ¹/4% Senior Notes and Our Other Indebtedness

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt, including our 10 ¹/4% senior notes.

     As of December 31, 2007, we had total debt of approximately $205.4 million (of which $150.0 million consisted of our 10¹/4% senior notes due 2014 net of $4.6 million in unamortized issue discount and $60.0 million consisted of borrowings under our revolving credit facility, excluding letters of credit). Our level of debt could have important consequences for you, including the following:

• we may have difficulty borrowing money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations;

• we will need to use a substantial portion of our cash flows to pay principal and interest on our debt, which will reduce the amount of money we have for operations, working capital, capital expenditures, expansion, acquisitions or general corporate or other business activities;

• we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;

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• we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially declines in oil and natural gas prices; and

• our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

We may incur substantially more debt, which may intensify the risks described above, including our ability to service our indebtedness.

     We may be able to incur substantially more debt in the future. Although the Indenture governing our 10¹/4% senior notes and the amended and restated credit agreement governing our revolving credit facility contain restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. As of December 31, 2007, we had approximately $140.0 million of additional borrowing capacity under our revolving credit facility, excluding letters of credit, subject to specific requirements, including compliance with financial covenants. In addition, the Indenture governing our 10¹/4% senior notes and our revolving credit facility do not prevent us from incurring obligations that do not constitute indebtedness. To the extent new indebtedness is added to our current indebtedness levels, the risks described above could substantially intensify.

To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of operations.

     Our ability to make payments on and to refinance our indebtedness, including the 10¹/4% senior notes, and to fund planned capital expenditures will depend on our ability to generate cash from operations in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, including the prices that we receive for oil and natural gas. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our revolving credit facility in an amount sufficient to enable us to pay our indebtedness, including the notes, or to fund our other liquidity needs.

     If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. The Indenture governing our 10¹/4% senior notes and the amended and restated credit agreement governing our revolving credit facility restrict our ability to dispose of assets and use the proceeds from the disposition. We cannot assure you that any of these remedies could, if necessary, be effected on commercially reasonable terms, or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness, including our revolving credit facility, would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. If we fail to meet our payment obligations under our revolving credit facility, those lenders would be entitled to foreclose on substantially all of our assets and liquidate those assets. Under those circumstances, our cash flow and capital resources could be insufficient for payment of interest on and principal of our debt in the future, including payments on our 10¹/4% senior notes, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations, impair our liquidity, or cause the holders of our 10¹/4% senior notes to lose a portion of or the entire value of their investment.

     A default on our obligations could result in:

• our debt holders declaring all outstanding principal and interest due and payable;

• the lenders under our revolving credit facility terminating their commitments to loan us money and foreclose against the assets securing their loans to us; and

• our bankruptcy or liquidation, which is likely to result in delays in the payment of our 10¹/4% senior notes and in the exercise of enforcement remedies under our 10¹/4% senior notes.

     In addition, provisions under the bankruptcy code or general principles of equity that could result in the impairment of your rights include the automatic stay, avoidance of preferential transfers by a trustee or a debtor-in-possession, limitations of collectibility of unmatured interest or attorneys’ fees and forced restructuring of our 10¹/4% senior notes.

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Restrictive debt covenants in the Indenture and the amended and restated credit agreement governing our revolving credit facility restrict our business in many ways.

     The Indenture governing our 10¹/4% senior notes contains a number of significant covenants that, among other things, restrict our ability to:

• transfer or sell assets;

• make investments;

• pay dividends, redeem subordinated indebtedness or make other restricted payments;

• incur or guarantee additional indebtedness or issue disqualified capital stock;

• create or incur liens;

• incur dividend or other payment restrictions affecting certain subsidiaries;

• consummate a merger, consolidation or sale of all or substantially all of our assets;

• enter into transactions with affiliates; and

• engage in businesses other than the oil and gas business.

     These covenants could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants impose on us. A breach of any of these covenants could result in a default under the 10¹/4% senior notes which, if not cured or waived, could result in acceleration of the 10¹/4% senior notes.

     In addition, the amended and restated credit agreement governing our revolving credit facility contains restrictive covenants and requires us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those tests. A breach of any of these covenants could result in a default under the facility. Upon the occurrence of an event of default, the lenders could elect to declare all amounts outstanding to be immediately due and payable and terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness. We have pledged substantially all of our assets as collateral under the revolving credit facility. If the lenders accelerate the repayment of borrowings, we cannot assure you that we will have sufficient assets to repay our revolving credit facility and our other indebtedness, including the 10¹/4% senior notes.

Our borrowings under our revolving credit facility expose us to interest rate risk.

     Our borrowings under our revolving credit facility are, and are expected to continue to be, at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.

We are subject to many restrictions under our revolving credit facility. If we default under our revolving credit facility, the lenders could foreclose on, and acquire control of, substantially all of our assets.

     Our revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion, based upon projected revenues from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Any increase in the borrowing base requires the consent of all lenders. If all lenders do not agree on an increase, then the borrowing base will be the lowest borrowing base determined by any lender. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil and natural gas properties as additional collateral. We do not currently have any substantial properties that are not pledged and no assurance can be given that we would be able to make any mandatory principal prepayments required under the revolving credit facility.

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     The lenders under our revolving credit facility have liens on substantially all of our assets. Additionally, the revolving credit facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We are also required to comply with certain financial covenants and ratios under this facility. Although we were in compliance with these covenants at December 31, 2007, in the past we have had to request waivers from our banks because of our non-compliance with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. As a result of the liens held by our lenders, if we fail to meet our payment or other obligations under this credit facility, including our failure to meet any of the required financial covenants or ratios, the lenders would be entitled to foreclose on substantially all of our assts and liquidate those assets. Our failure to comply with any of the restrictions and covenants under the revolving credit facility could result in a default under both the revolving credit facility and the Indenture governing our 10¹/4% senior notes, which could cause all of our existing indebtedness to be immediately due and payable.

Our 10¹/4% senior notes are structurally subordinated to any of our secured indebtedness to the extent of the assets securing such indebtedness.

     Our obligations under the 10¹/4% senior notes are unsecured, but our obligations under our revolving credit facility are secured by liens on substantially all of our assets. Holders of this indebtedness and any other secured indebtedness that we may incur in the future will have claims with respect to our assets constituting collateral for such indebtedness that are prior to claims of holders of the 10¹/4% senior notes. In the event of a default on such secured indebtedness or our bankruptcy, liquidation or reorganization, those assets would be available to satisfy obligations with respect to the indebtedness secured thereby before any payment could be made on the 10¹/4% senior notes. Accordingly, any such secured indebtedness will effectively be senior to the 10¹/4% senior notes to the extent of the value of the collateral securing the indebtedness. While the Indenture governing the 10¹/4% senior notes places some limitations on our ability to create liens, there are significant exceptions to these limitations that will allow us to secure some kinds of indebtedness without equally and ratably securing the 10¹/4% senior notes, including any future indebtedness we may incur under a credit facility. To the extent the value of the collateral is not sufficient to satisfy our secured indebtedness, the holders of that indebtedness would be entitled to share with the holders of the 10¹/4% senior notes and the holders of other claims against us with respect to our other assets. As of December 31, 2007, we had approximately $60 million in secured indebtedness outstanding under our revolving credit facility, excluding letters of credit.

A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state laws, which would prevent the holders of our 10¹/4% senior notes from relying on the subsidiary to satisfy our payment obligations under the 10¹/4% senior notes.

     Initially, there will be no subsidiary guarantees of the 10¹/4% senior notes, but in the future such guarantees may occur. Federal and state statutes allow courts, under specific circumstances, to void subsidiary guarantees, or require that claims under the subsidiary guarantee be subordinated to all other debts of the subsidiary guarantor, and to require creditors such as the noteholders to return payments received from subsidiary guarantors. Under federal bankruptcy law and comparable provisions of state fraudulent transfer laws, a subsidiary guarantee could be voided or claims in respect of a subsidiary guarantee could be subordinated to all other debts of that subsidiary guarantor if, for example, the subsidiary guarantor, at the time it issued its subsidiary guarantee:

• was insolvent or rendered insolvent by making the subsidiary guarantee;

• was engaged in a business or transaction for which the subsidiary guarantor’s remaining assets constituted unreasonably small capital; or

• intended to incur, or believed that it would incur, debts beyond its ability to pay them as they mature.

     A guarantee may also be voided, without regard to the above factors, if a court found that the guarantor entered into the guarantee with the actual intent to hinder, delay or defraud any present or future creditor or received less than reasonably equivalent value or fair compensation for the subsidiary guarantee. A court would likely find that a guarantor did not receive reasonably equivalent value or fair compensation for its guarantee if the guarantor did not substantially benefit directly or indirectly from the issuance of the guarantees.

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     The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred.

     Generally, a subsidiary guarantor would be considered insolvent if:

• the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;

• the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

• it could not pay its debts as they become due.

     To the extent a court voids a subsidiary guarantee as a fraudulent transfer or holds the subsidiary guarantee unenforceable for any other reason, holders of 10¹/4% senior notes would cease to have any direct claim against the subsidiary guarantor. If a court were to take this action, the subsidiary guarantor’s assets would be applied first to satisfy the subsidiary guarantor’s liabilities, if any, before any portion of its assets could be distributed to us to be applied to the payment of the 10¹/4% senior notes. We cannot assure you that a subsidiary guarantor’s remaining assets would be sufficient to satisfy the claims of the holders of 10¹/4% senior notes related to any voided portions of the subsidiary guarantees.

We may not have sufficient liquidity to repurchase the 10¹/4% senior notes upon a change of control.

     Upon the occurrence of a change of control, holders of 10¹/4% senior notes will have the right to require us to repurchase all or any part of such holder’s 10¹/4% senior notes at a price equal to 101% of the principal amount of the 10¹/4% senior notes, plus accrued and unpaid interest, if any, to the date of repurchase. We may not have sufficient funds at the time of the change of control to make the required repurchases, or restrictions under our revolving credit facility may not allow such repurchases. In addition, an event constituting a “change of control” (as defined in the indenture governing the 10¹/4% senior notes) could be an event of default under our revolving credit facility that would, if it should occur, permit the lenders to accelerate that debt and that, in turn, would cause an event of default under the indenture governing the 10¹/4% senior notes, each of which could have material adverse consequences for us and the holders of the 10¹/4% senior notes. The source of any funds for any repurchase required as a result of a change of control will be our available cash or cash generated from our business operations or other sources, including borrowings, sales of assets, sales of equity or funds provided by a new controlling entity. We cannot assure you, however, that sufficient funds would be available at the time of any change of control to make any required repurchases of the 10¹/4% senior notes tendered and to repay debt under our revolving credit facility.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

     We have not received any written comments from the staff of the Securities and Exchange Commission that remain unresolved.

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ITEM 2. PROPERTIES

General

          Our principal properties consist of working interests in developed and undeveloped oil and natural gas leases and the reserves associated with those leases. Generally, developed oil and natural gas leases remain in force so long as production is maintained. Undeveloped oil and natural gas leaseholds are generally for a primary term of five or ten years. In most cases, we can extend the term of our undeveloped leases by paying delay rentals or by producing reserves that we discover under our leases.

          The map below shows our principal areas of operations.

     

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Producing Wells and Acreage

     We have presented the table below to provide you with a summary of the producing oil and natural gas wells and the developed and undeveloped acreage in which we owned an interest at December 31, 2007. We have not included in the table acreage in which our interest is limited to options to acquire leasehold interests, royalty or similar interests. Also excluded are 150 gross wells for which we were serving as operator at December 31, 2007, but in which we did not own an interest.

	Producing Wells(1)								Acreage
	Oil(2)				Gas				Developed				Undeveloped
	Gross		Net(3)		Gross		Net(3)		Gross		Net(4)		Gross		Net(4)
Resource Projects
Barnett Shale		—		—		55		14.68		2,400		785		26,363		7,774
New Mexico		—		—		69		32.30		13,877		8,920		92,480		68,347
Total Resource Projects		—		—		124		46.98		16,277		9,705		118,843		76,121
Permian Basin of West Texas
Fullerton		151		127.50		—		—		3,683		3,155		—		—
Carm-Ann/N. Means Queen		89		75.84		—		—		5,560		4,843		235		235
Harris		69		61.75		—		—		1,303		1,176		1,816		1,783
Diamond M		50		32.94		—		—		5,805		3,809		—		—
Other Permian		73		31.66		28		12.67		23,079		15,469		—		—
Total Permian Basin		432		329.69		28		12.67		39,430		28,452		2,051		2,018
Onshore Gulf Coast of South Texas
Yegua/Frio/Wilcox		3		0.62		34		8.45		4,732		1,993		2,734		1,022
Cook Mountain		—		—		12		1.31		1,059		150		74		14
Total Onshore Gulf Coast of South Texas		3		0.62		46		9.76		5,791		2,143		2,808		1,036
Other Projects
Cotton Valley		—		—		2		0.30		561		74		10,463		1,077
Utah/Colorado		—		—		—		—		—		—		163,196		155,454
Total Other Projects		—		—		2		0.30		561		74		173,659		156,531
Grand Total		435		330.31		200		69.71		62,059		40,374		297,361		235,706

(1)	Does not include 175 gross (79.07 net) wells that were shut in or temporarily abandoned as of December 31, 2007.
(2)	Does not include 128 gross (98.30 net) injection wells as of December 31, 2007.
(3)	Net wells are computed by multiplying the number of gross wells by our working interest in the gross wells.
(4)	Net acres are computed by multiplying the number of gross acres by our working interest in the gross acres.

     At December 31, 2007, we owned interests in 369 gross (306.55 net) oil and natural gas wells for which we were the operator and 569 gross (270.84 net) oil and natural gas wells where we were not the operator.

     The operator of a well has significant control over its location and the timing of its drilling. In addition, the operator receives fees from other working interest owners as reimbursement for general and administrative expenses for operating the wells.

     Except for our oil and natural gas leases and related and seismic data, we do not own any patents, licenses, franchises or concessions which are significant to our oil and natural gas operations.

     For a more detailed description of our exploration and development activities, you should read “Item 1, Business — Current Drilling Projects” beginning on page 5 of this Annual Report on Form 10-K.

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Title to Properties

     As in customary in the oil and natural gas industry, we make only a cursory review of title to undeveloped oil and natural gas leases at the time they are acquired. These cursory title reviews, while consistent with industry practices, are necessarily incomplete. We believe that it is not economically feasible to review in depth every individual property we acquire, especially in the case of producing property acquisitions covering a large number of leases. Ordinarily, when we acquire producing properties, we focus our review efforts on properties believed to have higher values and will sample the remainder. However, even an in-depth review of all properties and records may not necessarily reveal existing or potential defects nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. In the case of producing property acquisitions, inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. In the case of undeveloped leases or prospects we acquire, before any drilling commences, we will usually cause a more thorough title search to be conducted, and any material defects in title that are found as a result of the title search are generally remedied before drilling a well on the lease commences. We believe that we have good title to our oil and natural gas properties, some of which are subject to immaterial encumbrances, easements and restrictions. The oil and natural gas properties we own are also typically subject to royalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materially affect our ownership or the use of our properties.

Oil and Natural Gas Reserves

     For the year ended December 31, 2007, our oil and natural gas reserves were estimated by Cawley Gillespie & Associates, Inc., Fort Worth, Texas.

     At December 31, 2007, our total estimated proved reserves were approximately 28.4 MMBbls of oil and approximately 57.2 Bcf of natural gas, or 38.0 MMBOE.

     The information in the following table provides you with certain information regarding our proved reserves as estimated by Cawley Gillespie & Associates, Inc. at December 31, 2007.

	Proved Developed		Proved Developed		Proved		Total
	Producing		Non-Producing		Undeveloped		Proved
Oil (MBbls)		13,570		808		14,056		28,434
Gas (MMcf)		41,375		181		15,678		57,234
MBOE		20,466		838		16,669		37,973

     Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are 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.

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     The table below shows the production from our oil and natural gas properties for the year ended December 31, 2007 and the proved reserves attributable to those properties as of December 31, 2007.

							Reserves
	Production						Total Proved				Proved Developed
			Natural						Natural				Natural
	Oil		Gas				Oil		Gas		Oil		Gas
	(MBbls)		(MMcf)		BOE		(MBbls)		(MMcf)		(MBbls)		(MMcf)
Resource Projects
Barnett Shale		—		3,030		505		—		17,714		—		14,530
New Mexico Wolfcamp		4		2,731		459		1		24,284		1		17,150
Total Resource Projects		4		5,761		964		1		41,998		1		31,680
Permian Basin of West Texas
Fullerton		536		110		554		9,358		1,744		8,945		1,661
Carm-Ann San Andres/N. Means Queen		161		146		186		6,554		4,159		1,694		1,161
Harris		194		42		201		8,086		1,113		2,362		467
Diamond M		80		107		98		3,855		2,195		796		562
Other Permian Basin		45		306		96		479		3,154		479		3,154
Total Permian Basin		1,016		711		1,135		28,332		12,365		14,276		7,005
Onshore Gulf Coast of South Texas		31		950		189		101		2,871		101		2,871
Total		1,051		7,422		2,288		28,434		57,234		14,378		41,556

     Estimates of our proved reserves and future net revenues are made using sales prices and costs, estimated to be in effect as of the date of our reserve estimates that are held constant throughout the life of the properties, except to the extent a contract specifically provides for escalation of prices or costs. The average prices utilized in the estimation of our reserve calculations as of December 31, 2007 were $89.93 per Bbl of oil and $6.77 per Mcf of natural gas.

     For additional information concerning our estimated proved oil and natural gas reserves, you should read Note 16 to the Consolidated Financial Statements.

     The reserve data in this Annual Report on Form 10-K represent estimates only. Reservoir engineering is a subjective process. There are numerous uncertainties inherent in estimating our oil and natural gas reserves and their estimated values. Many factors are beyond our control. Estimating underground accumulations of oil and natural gas cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment and the costs we actually incur in the development of our reserves. As a result, estimates of different engineers often vary. In addition, estimates of reserves are subject to revision by the results of drilling, testing and production after the date of the estimates. Consequently, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of estimates is highly dependent upon the accuracy of the assumptions upon which they were based.

     The volume of production from oil and natural gas properties declines as reserves are produced and depleted. Unless we acquire properties containing proved reserves or conduct successful drilling activities, our proved reserves will decline as we produce our existing reserves. Our future oil and natural gas production is highly dependent upon our level of success in acquiring or finding additional reserves.

     We do not have any oil or natural gas reserves outside the United States. Our oil and natural gas reserves and production are not subject to any long term supply or similar agreements with foreign governments or authorities.

     Our estimated reserves have not been filed with or included in reports to any federal agency other than the Securities and Exchange Commission.

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ITEM 3. LEGAL PROCEEDINGS

     On May 21, 2007, we received a Notice of Proposed Adjustment, or the “Notice” from the Internal Revenue Service, or the “Service”, advising us of proposed adjustments to our calculations of federal income tax resulting in a proposed alternative minimum tax liability in the aggregate amount of approximately $2.0 million for the years 2004 and 2005. After advising the Service that we intended to appeal the Notice, we received correspondence from the Service on July 10, 2007 stating that the issue remains in development pending receipt of additional documents requested and any proposed tax adjustment would not be made until after reviewing the documents requested. On November 5, 2007, we received an examination report related to this matter which reduces the amount of proposed adjustment to approximately $1.1 million, which includes interest. On December 21, 2007, we filed an appeal with the Service protesting the proposed adjustment of $1.1 million. We intend to vigorously contest the adjustment proposed by the Service and believe that we will ultimately prevail in our position. We would expect the recording of any adjustment, if later determined to be required, to entail recognition of a deferred tax asset and a corresponding current liability for federal income taxes payable. Such an adjustment would generally not result in a charge to earnings except for amounts which might be assessed for penalties or interest on underpayment of current tax for our fiscal years ended December 31, 2004 and 2005. If a liability for penalties or interest were determined to be probable, the amounts of such penalties and/or interest would be charged to earnings. We believe that the effects of this matter will not have a material adverse effect on our financial position or results of operations for any fiscal year, but could have a material adverse effect on our results of operations for the fiscal quarter in which we actually incur or establish a liability for penalties or interest.

     We are not a defendant in any other litigation or other proceedings and we are not aware of any other threatened material litigation, nor have we been a party to any bankruptcy, receivership, reorganization, adjustment or similar proceeding.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     We did not submit any matter to a vote of our stockholders during the fourth quarter of 2007.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

     Our common stock trades on the Nasdaq Global Market under the symbol “PLLL”. The following table shows, for the periods indicated, the high and low closing price per share for our common stock as reported on the Nasdaq Global Market.

	Price Per Share
	High		Low
2005
First Quarter	$	7.60	$	5.01
Second Quarter	$	9.00	$	6.26
Third Quarter	$	14.15	$	8.29
Fourth Quarter	$	18.52	$	11.41
2006
First Quarter	$	21.13	$	15.67
Second Quarter	$	25.56	$	18.47
Third Quarter	$	26.39	$	18.90
Fourth Quarter	$	20.96	$	16.34
2007
First Quarter	$	23.31	$	16.00
Second Quarter	$	24.69	$	21.79
Third Quarter	$	22.88	$	16.76
Fourth Quarter	$	20.96	$	16.65

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     The closing price of our common stock on February 1, 2008 was $14.38 per share, as reported on the Nasdaq Global Market.

     As of February 1, 2008, there were approximately 2,355 stockholders of record. This number does not include any beneficial owners for whom shares of common stock may be held in “nominee” or “street” name.

Dividends

     We have not paid, and do not intend to pay in the foreseeable future, cash dividends on our common stock. We intend to retain earnings to finance the expansion of our business and for general corporate purposes. Any declaration of dividends will be at the discretion of our Board of Directors and will depend upon the earnings, financial condition, capital requirements, level of indebtedness, contractual restrictions with respect to payment of dividends and other factors. Our revolving credit facility and the Indenture governing our 10¹/4% senior notes restrict our ability to pay dividends on our common stock. See “Risks Related to Our Common Stock — We do not pay dividends on our common stock” on page 20.

Sale of Unregistered Securities

     At our annual meeting of stockholders held on June 22, 2004, the stockholders approved the Parallel Petroleum Corporation 2004 Non-Employee Director Stock Grant Plan. You can find a description of this plan on page 83. Historically, Director’s fees had been paid solely in cash. However, upon approval of the plan by the stockholders, we began paying an annual retainer fee to each non-employee Director in the form of common stock. Only Directors of Parallel who are not employees of Parallel or any of its subsidiaries are eligible to participate in the plan. Under the plan, each non-employee Director is entitled to receive an annual retainer fee consisting of shares of common stock that are automatically granted on the first day of July in each year, beginning on July 1, 2004. The actual number of shares received is determined by dividing $25,000 by the average daily closing price of the common stock on the Nasdaq Global Market for the ten consecutive trading days commencing fifteen trading days be-fore the first day of July of each year. On July 1, 2007, and in accordance with the terms of the plan, a total of 4,400 shares of common stock were granted to four non-employee Directors as follows: Jeffrey G. Shrader — 1,100 shares; Edward A. Nash — 1,100 shares; Martin B. Oring — 1,100 shares; and Ray M. Poage — 1,100 shares. The shares of common stock were issued without registration under the Securities Act of 1933, as amended, in reliance on the exemption provided by Section 4(2) of the Securities Act of 1933, as amended. Generally, shares issued under this plan are not transferable as long as the non-employee Director holding the shares remains a Director of Parallel.

     On July 31, 2007, we completed a private offering of unsecured 10¹/4% senior notes in the principal amount of $150.0 million. The net proceeds, after payment of typical transaction expenses, of the senior notes of approximately $143.5 million were used first to retire all of our indebtedness under our Second Lien Term Loan Agreement, with the remainder being applied to the repayment of indebtedness under our revolving credit facility.

Repurchase of Equity Securities

     Neither we nor any “affiliated purchaser” repurchased any of our equity securities during the fourth quarter of the fiscal year ended December 31, 2007.

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ITEM 6. SELECTED FINANCIAL DATA

          In the table below, we provide you with selected historical financial data. We have prepared this information using our audited Consolidated Financial Statements for the five-year period ended December 31, 2007. It is important that you read this data along with our audited Consolidated Financial Statements and related notes, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Item 7 below. The selected financial data provided are not necessarily indicative of our future results of operations or financial performance.

	Year Ended December 31,
	2007			2006(1)			2005			2004			2003
				($ in thousands, except per share and per unit data)
Consolidated Income Statements Data:
Operating revenues	$	116,031		$	97,025		$	66,150		$	35,837		$	33,855
Operating expenses	$	67,066		$	56,606		$	32,805		$	23,571		$	21,138
Income (loss) before cumulative effect of change in accounting principle	$	(4,661	)	$	26,155		$	(1,589	)	$	2,271		$	7,664
Net income (loss)	$	(4,661	)	$	26,155		$	(1,589	)	$	2,271		$	7,602
Cumulative preferred stock dividend	$	—		$	—		$	(271	)	$	(572	)	$	(580	)
Net income (loss) available to common stockholders	$	(4,661	)	$	26,155		$	(1,860	)	$	1,699		$	7,022
Income (loss) per common share before cumulative effect of change in accounting principle
Basic	$	(0.12	)	$	0.73		$	(0.06	)	$	0.07		$	0.33
Diluted	$	(0.12	)	$	0.71		$	(0.06	)	$	0.07		$	0.31
Weighted average common stock and common stock equivalents outstanding
Basic		38,120			35,888			32,253			25,323			21,264
Diluted		38,120			36,756			32,253			25,688			24,175
Cash dividends — common stock	$	—		$	—		$	—		$	—		$	—
Consolidated Balance Sheet Data:
Total assets	$	563,093		$	442,818		$	253,008		$	170,671		$	118,343
Total liabilities	$	327,831		$	259,036		$	163,506		$	110,677		$	57,111
Long-term debt, less current maturities	$	205,383		$	165,000		$	100,000		$	79,000		$	39,750
Total stockholders’ equity	$	235,262		$	183,782		$	89,502		$	59,994		$	61,232
Consolidated Statement of Cash Flow Data:
Cash provided by (used in)
Operating activities	$	76,619		$	74,186		$	37,118		$	18,156		$	19,493
Investing activities	$	(167,397	)	$	(200,548	)	$	(84,949	)	$	(69,518	)	$	(15,494	)
Financing activities	$	92,684		$	125,854		$	49,468		$	38,765		$	1,567
Operating Data:
Product Sales
Oil (Bbls)		1,051			1,137			923			729			629
Gas (Mcf)		7,422			6,539			3,592			2,690			3,356
BOE		2,288			2,227			1,522			1,177			1,188
Average sales price(2)
Oil (per Bbl)	$	65.97		$	59.86		$	51.78		$	39.05		$	29.11
Gas (per M cf)	$	6.29		$	6.19		$	8.54		$	5.85		$	5.40
Proved reserves
Oil (Bbls)		28,434			28,721			21,192			18,916			12,084
Gas (M cf)		57,234			58,896			25,237			16,825			16,271

(1)	Results include $9.0 million of equity in income of pipeline and gathering systems representing Parallel’s share of net gain on sale of certain pipeline assets.
(2)	Excludes the effects of hedging.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     The following discussion is intended to assist you in understanding our financial position and results of operations for each year in the three-year period ended December 31, 2007. You should read the following discussion and analysis in conjunction with our selected financial data and our accompanying audited Consolidated Financial Statements and the related notes to those financial statements included elsewhere in this report.

     The following discussion contains forward-looking statements. For a description of limitations inherent in forward-looking statements, see “Cautionary Statement Regarding Forward-Looking Statements” on page (ii).

Overview and Strategy

     We are a Midland, Texas-based independent oil and natural gas exploration and production company focused on the acquisition, development and exploitation of long-lived oil and natural gas reserves and, to a lesser extent, exploring for new oil and natural gas reserves. The majority of our current producing properties are in the Permian Basin of West Texas and New Mexico, the Fort Worth Basin of North Texas, and the onshore Gulf Coast area of South Texas.

     Our primary objective is to increase stockholder value by increasing reserves, production, cash flow and earnings. We have shifted the balance of our investments from properties having high rates of production in early years to properties expected to produce more consistently over a longer term. We attempt to reduce our financial risks by dedicating a smaller portion of our capital to high risk projects, while reserving the majority of our available capital for acquisitions, exploitation and development drilling opportunities. Obtaining positions in long-lived oil and natural gas reserves are given priority over properties that might provide more cash flow in the early years of production, but which have shorter reserve lives. We also attempt to further reduce risk by emphasizing acquisition possibilities over high risk exploration projects.

     Since the latter part of 2002, we have reduced our emphasis on high risk exploration efforts and started focusing on established geologic trends where we can utilize the engineering, operational, financial and technical expertise of our entire staff. Although we expect to continue participating in exploratory drilling activities, reducing financial, reservoir, drilling and geological risks and diversifying our property portfolio are important criteria in the execution of our business plan. In summary, our current business plan:

• focuses on projects having less geologic risk;

• emphasizes acquisition, exploitation, development and enhancement activities;

• includes the utilization of horizontal and fracture stimulation technologies on certain types of reservoirs;

• focuses on acquiring producing properties; and

• expands the scope of operations by diversifying our exploratory and development efforts, both in and outside of our current areas of operation.

     Although the direction of our exploration and development activities has shifted from higher-risk exploratory activities to lower-risk development opportunities, we will continue our efforts, as we have in the past, to maintain low general and administrative expenses relative to the size of our overall operations, utilize advanced technologies, serve as operator in appropriate circumstances, and reduce operating costs.

     The extent to which we are able to implement and follow through with our business plan will be influenced by:

• the prices we receive for the oil and natural gas we produce;

• the results of reprocessing and reinterpreting our 3-D seismic data;

• the results of our drilling activities;

• the costs of obtaining high quality field services;

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• our ability to find and consummate acquisition opportunities; and

• our ability to negotiate and enter into work to earn arrangements, joint venture or other similar agreements on terms acceptable to us.

          Significant changes in the prices we receive for our oil and natural gas, or the occurrence of unanticipated events beyond our control may cause us to defer or deviate from our business plan, including the amounts we have budgeted for our activities.

Operating Performance

          Our operating performance is influenced by several factors, the most significant of which are the prices we receive for our oil and natural gas and the quantities of oil and natural gas that we are able to produce. The world price for oil has overall influence on the prices that we receive for our oil production. The prices received for different grades of oil are based upon the world price for oil, which is then adjusted based upon the particular grade. Typically, light oil is sold at a premium, while heavy grades of crude are discounted. Natural gas prices we receive are influenced by:

• seasonal demand;

• weather;

• hurricane conditions in the Gulf of Mexico;

• availability of pipeline transportation to end users;

• proximity of our wells to major transportation pipeline infrastructures; and

• world oil prices.

Results of Operations

          As described under “Item 1. Business — About Our Business and Strategy”, we changed our business model in 2002. At the beginning of 2002, our total proved reserves were approximately 3.2 MMBoe with a reserves to production ratio of approximately 4 to 1. Through the execution of this business model, our reserves at the end of 2007 were approximately 38.0 MMBoe with a reserves to production ratio of approximately 16.6 to 1. As described on page 13 of this Annual Report on Form 10-K, the failure to replace oil and natural gas reserves may negatively affect our business. We monitor this risk by comparing the quantity of our oil and natural gas reserves at the end of each year to our production for that year. This comparison, which is made in the form of a reserves to production ratio, helps us measure our ability to offset produced volumes with new reserves that will be produced in the future. The reserves to production ratio is calculated by dividing the total proved reserves at the end of a year by the actual production for the same year. The annual change in this ratio provides us with an indication of our performance in replenishing annual production volumes. The reserves to production ratio is a statistical indicator that has limitations. The ratio is limited because it can vary widely based on the extent and timing of new discoveries and property acquisitions. In addition, the ratio does not take into account the cost or timing of future production of new reserves. For that reason, the ratio does not, and is not intended to, provide a measurement of value. For the year ended 2002, our production was 77% natural gas and 23% oil, as compared to approximately 54% natural gas and 46% oil for the year ended December 31, 2007. The production stream changed from shorter lived gulf coast natural gas to longer lived Permian Basin oil production and longer lived natural gas production in the Barnett Shale and New Mexico Wolfcamp areas. This has increased our lease operating expense primarily due to increased utilities and chemicals associated with the operation of oil properties and salt water disposal and compression associated with these longer lived resource gas projects.

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     The following table shows selected data and operating income comparisons for each of the three years ended December 31, 2007.

	Years Ended December 31,
	2007			2006			2005
	($ in thousands, except per unit data)
Production Volumes
Oil (Bbls)		1,051			1,137			923
Natural gas (Mcf)		7,422			6,539			3,592
BOE		2,288			2,227			1,522
Sales Price
Oil (per Bbl)(1)	$	65.97		$	59.86		$	51.78
Natural gas (per Mcf)(1)	$	6.29		$	6.19		$	8.54
BOE Price(1)	$	50.72		$	48.73		$	51.57
BOE Price(2)	$	50.72		$	43.56		$	43.46
Operating Revenues
Oil	$	69,315		$	68,076		$	47,800
Effect of oil hedges		—			(11,512	)		(12,139	)
Natural gas		46,716			40,461			30,690
Effect of natural gas hedges		—			—			(201	)
		116,031			97,025			66,150
Operating Expenses
Lease operating expense		22,200			16,819			9,947
Production taxes		5,545			5,577			4,102
Production tax refund		(1,209	)		—			—
General and administrative		10,415			9,523			6,712
Depreciation, depletion and amortization		30,115			24,687			12,044
		67,066			56,606			32,805
Operating income	$	48,965		$	40,419		$	33,345

(1)	Excludes hedge transactions.
(2)	Includes hedge transactions.

Critical Accounting Policies and Practices

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses. Certain accounting policies that require significant management estimates and that are deemed critical to our results of operations or financial position are discussed below. Our management reviews our critical accounting policies with the Audit Committee of our Board of Directors.

     Full Cost and Impairment of Assets. We account for our oil and natural gas exploration and development activities using the full cost method of accounting. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized. Costs of non-producing properties, wells in process of being drilled and significant development projects are excluded from depletion until such time as the related project is developed and proved reserves are established or impairment is determined. At the end of each quarter, the net capitalized costs of our oil and natural gas properties, net of related deferred taxes, is limited to the lower of unamortized cost or a ceiling, based on the present value of estimated future net revenues, net of income tax effects, discounted at 10%, plus the lower of cost or fair market value of our unproved properties. Estimated future net revenues are measured at unescalated oil and natural gas prices at the end of each quarter, with effect given to our cash flow hedge positions. If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are subject to a ceiling test write-down to the extent of the excess. A ceiling test write-down is a non-cash charge to

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earnings. It reduces earnings and impacts stockholders’ equity in the period of occurrence and may result in lower depreciation, depletion and amortization expense in future periods.

     The risk that we will be required to write down the carrying value of oil and natural gas properties increases when oil and natural gas prices decline. If commodity prices deteriorate, it is possible that we could incur an impairment in future periods.

     Depletion. Provision for depletion of oil and natural gas properties under the full cost method is calculated using the unit of production method based upon estimates of proved oil and natural gas reserves with oil and natural gas production being converted to a common unit of measurement based upon relative energy content. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. The cost of any impaired property is transferred to the balance of oil and natural gas properties subject to depletion. The amortizable base includes estimated future development costs and where significant, dismantlement, restoration and abandonment costs, net of estimated salvage value. Oil and natural gas properties included $86.4 million and $50.4 million for 2007 and 2006, respectively, for unevaluated properties not included in depletion.

     In arriving at rates under the unit of production method, the quantities of recoverable oil and natural gas reserves are established based on estimates made by our geologists and engineers and require significant judgment as does the projection of future production volumes and levels of future costs, including future development costs. In addition, considerable judgment is necessary in determining when unproved properties become impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may have significant impact on the calculation of depletion expense. There have been no material changes in our methodology of calculating the depletion of oil and gas properties under the full cost method during the three years ended December 31, 2007.

     Proved Reserve Estimates. The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our reserve estimates are prepared by independent petroleum engineers.

     The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. If future revisions significantly reduce previously estimated reserve quantities, it could result in a full cost ceiling write-down. At December 31, 2007, our ceiling was in excess of our capitalized costs. In addition to the impact of the estimates of proved reserves in calculating the ceiling test, estimates of proved reserves are also a significant component of the calculations of depreciation, depletion and amortization.

     While estimates of the quantities of proved reserves require substantial subjective judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. Accounting principles generally accepted in the United States require that prices and costs in effect as of the last day of the period are held constant indefinitely. Accordingly, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and, on the last day of a quarter, can be either substantially higher or lower than prices we actually receive in the long-term, which are a barometer for true fair value.

     Use of Estimates. The preparation of our Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported assets, liabilities, expenses, and some narrative disclosures. Hydrocarbon reserves, future development costs and certain hydrocarbon production expenses are the most critical estimates used in the preparation of our Consolidated Financial Statements.

     Derivatives. The Financial Accounting Standards Board issued SFAS No. 133, as amended by SFAS No. 138, that requires all derivative instruments to be recorded on the balance sheet at their respective fair values. We adopted SFAS no. 133 on January 1, 2001.

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     During the period from January 1, 2003 to June 30, 2004, new derivative contracts were designated as cash flow hedges. These contracts remained designated as cash flow hedges through their settlement. Accordingly, the effective portion of the unrealized gains or losses was recorded in other comprehensive loss until the settlement of the contract position occurred. At settlement of these contracts, the cash value paid was recorded in revenue along with oil and natural gas sales, or in interest expense along with the interest expense that we incurred under our credit facilities. As of December 31, 2006, we had no remaining contracts which were designated as hedges.

     For periods prior to 2003 and for periods after July 1, 2004, derivative contracts entered into were not designated as cash flow hedges. Accordingly, the unrealized gain or loss on these derivative contracts was recorded in other income. At settlement of these contracts, the realized gain or loss remains in other income and is not offset against oil and natural gas sales or interest expense.

     Although we have designated our derivative contracts differently in different periods, the purpose of all of our derivative contracts is to provide a measure of stability in our oil and natural gas receipts and interest rate payments and to manage exposure to commodity price and interest rate risk under existing sales contracts.

Years Ended December 31, 2007 and December 31, 2006

     Our oil and natural gas revenues and production product mix are shown in the following table for the years ended December 31, 2007 and 2006.

     Oil and Gas Revenues

	Revenues(1)						Production
	2007			2006			2007			2006
Oil (Bbls)		60	%		58	%		46	%		51	%
Natural gas (Mcf)		40	%		42	%		54	%		49	%
Total		100	%		100	%		100	%		100	%

(1) Includes the effects of derivative transactions accounted for as hedges.

     The following table shows our production volumes, product sale prices and operating revenues for the periods indicated.

									Percent
	Year Ended December 31,					Increase			Increase
	2007		2006			(Decrease)			(Decrease)
	($ in thousands, except per unit data)
Production Volumes
Oil (Bbls)		1,051		1,137			(86	)		(8	)%
Natural gas (Mcf)		7,422		6,539			883			14	%
BOE		2,288		2,227			61			3	%
Sales Price
Oil (per Bbl)(1)	$	65.97	$	59.86		$	6.11			10	%
Natural gas (per Mcf)(1)	$	6.29	$	6.19		$	0.10			2	%
BOE price(1)	$	50.72	$	48.73		$	1.99			4	%
BOE price(2)	$	50.72	$	43.56		$	7.16			16	%
Operating Revenues
Oil	$	69,315	$	68,076		$	1,239			2	%
Effect of oil hedges		—		(11,512	)		11,512			(100	)%
Natural gas		46,716		40,461			6,255			15	%
Total	$	116,031	$	97,025		$	19,006			20	%

(1)	Excludes hedge transactions.
(2)	Includes hedge transactions.

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Oil revenues

     Average wellhead realized crude oil prices increased $6.11 per Bbl, or 10%, to $65.97 per Bbl for 2007, as compared to 2006. This price increase caused our revenues to increase by approximately $6.4 million in 2007, as compared to 2006. Oil production decreased 8% attributable to a decline of approximately 43,000 Bbls, 41,000 Bbls and 33,000 Bbls in the Diamond M Deep, Carm-Ann and south Texas area, respectively comparing the twelve months ended December 31, 2007 to twelve months ended December 31, 2006. These decreases were as a result of natural declines and limited developmental activity occurring within these areas. These decreases were partially offset with increases in the Harris field where we benefited from our development programs in 2006 and late 2007. The decrease in oil production reduced revenue approximately $5.2 million for 2007.

Natural gas revenues

     Average realized wellhead natural gas prices received were up slightly to $6.29 per Mcf for the twelvemonths ended December 31, 2007 from $6.19 per Mcf received for the twelve months ended December 31, 2006. This slight price increase accounted for an increase in revenue of approximately $742,000. Natural gas production increased 14% primarily due to new wells in New Mexico Wolfcamp area where volumes were up 1.7 Bcf and the Barnett Shale area where volumes were up approximately 628,000 Mcf. These increases were offset by a production decline of approximately 1.2 Bcf in our south Texas wells comparing twelve months ended December 31, 2007 to twelve months ended December 31, 2006. The net increase in natural gas volumes increased revenue approximately $5.5 million for 2007.

Oil hedges

     We settled all remaining derivatives classified as cash flow hedges in December 2006. Therefore, oil hedge losses were $0 in 2007 compared to a loss of approximately $11.5 million in 2006. We continue to employ derivative contracts in the form of oil and natural collars and swaps which are intended to mitigate the effects of commodity price volatility. These derivative contracts are not designated or accounted for as cash flow hedges and, therefore, the changes in their fair values and any settlement amounts are recorded to other income (expense) as described below.

     Costs and Expenses

									Percent
	Year Ended December					Increase			Increase
	2007			2006		(Decrease)			(Decrease)
	($ in thousands)
Lease operating expense	$	22,200		$	16,819	$	5,381			32	%
Production taxes		5,545			5,577		(32	)		(1	)%
Production tax refund		(1,209	)		—		(1,209	)		N/A
General and administrative		10,415			9,523		892			9	%
Depreciation, depletion and amortization		30,115			24,687		5,428			22	%
Total	$	67,066		$	56,606	$	10,460			18	%

Lease operating expense

     Lease operating expenses are higher partly due to new wells. Of the $5.4 million increase, $2.3 million of these charges are on wells that have been completed in the past year or completed late in 2006. Therefore, the costs are higher for the twelve months ended December 31, 2007 compared to the same period 2006. Well repair, workover expenses, salt water disposal and compressor expense increased approximately $4.0 million for the twelve months ended December 31, 2007 compared to the twelve months ended December 31, 2006. Overall higher costs for well repair and workover result from our refocused efforts on lease maintenance and away from developmental activity during 2007 on our oil properties. Salt water disposal and compression charges increased significantly during 2007 resulting from new well activity in the south New Mexico area and Barnett shale area. These amounts are included in the previously discussed $2.3 million increase for new wells. Lifting costs (excluding production taxes) were $9.70 per BOE in 2007 compared to $7.55 per BOE in 2006.

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Production taxes

     Production taxes showed no significant change even though revenue increased $7.5 million from December 31, 2006 to December 31, 2007. The expected increase was offset by qualifying lower severance tax rates used during 2007. The lower severance tax rates are a result of certain properties qualifying for state tax incentive programs. The lower tax rates will continue on a forward basis until the term of the tax incentives are expired.

     A production tax refund was received in June 2007 in the amount of $1.2 million for gas production taxes on non-operated wells in the Wilcox area of south Texas for production periods March 2005 through January 2007. This refund was received by the operator of these wells only after the operator’s application for tax abatement was approved by state regulatory agencies. The reduction in our production tax expense was recognized only when approval of the application for tax abatement was granted by the state.

General and administrative

     General and administrative expenses increased 9% or $892,000 in 2007 over 2006. During 2007, salaries increased by $488,000. This was due to a larger staff and increased salary rates when compared to 2006. Also, we incurred increased legal fees in 2007 in the amount of $413,000. This increase in legal fees was primarily related to general corporate matters. In addition, we incurred increased costs of $334,000 associated with accounting and reporting requirements. Although there can be no assurance, we do not expect legal, accounting and reporting costs to increase significantly in 2008. Our insurance premiums increased by $219,000.

     Offsetting the above general and administrative expense increases were the following two items. First, during the second quarter of 2006, we determined that stock options to purchase 30,000 shares of common stock had been granted in 2003 to four of our employees under our 1998 Stock Option Plan, but which were not available for issuance under the plan. In June 2006, the Board of Directors authorized us to enter into settlement and release agreements with the four employees. Under these agreements, we made a one-time lump sum cash payment to each employee in an amount equal to the “spread” between the exercise price of the options and the closing price of our stock on June 21, 2006. The total cash payments were approximately $511,000. This amount was charged to general and administrative expense during the second quarter of 2006. Secondly, during the second quarter of 2007, we revised our estimates of expected forfeitures of stock options granted to directors due to the resignation of a director and the subsequent forfeiture of 40,000 stock options held by him. As a result we reduced our estimate of the grant date fair value of shares expected to ultimately vest under our stock option plan by approximately $283,000.

Depreciation, depletion and amortization

     Depreciation, depletion and amortization expense increased 22%, or $5.4 million, for 2007 as compared to 2006. Depletion per BOE was $13.02 for 2007 and $10.88 for 2006. This increase is attributable to an overall increase in actual and anticipated drilling costs and related oilfield service costs. Increased cost levels affect both the depletable amounts of capitalized costs in 2007 and the depletion attributable to amounts of estimated future development costs on proved undeveloped properties. Throughout 2006 and 2007, the majority of our drilling activity was in our natural gas resource projects in the Permian Basin of west Texas and the Barnett Shale areas. These areas have higher associated per BOE drilling and development costs due to the use of horizontal drilling and multi-stage stimulation techniques. These factors, when combined with the increase in the absolute level of our capital expenditures during this time period have led to a significant increase in our depletion rate per BOE.

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     Other income (expense)

										Percent
	Year Ended December						Increase			Increase
	2007			2006			(Decrease)			(Decrease)
	($ dollars in thousands)
Gain (loss) on derivatives not classified as hedges	$	(36,776	)	$	2,802		$	(39,578	)		(1,412	)%
Gain (loss) on ineffective portion of hedges		—			626			(626	)		(100	)%
Interest and other income		197			158			39			25	%
Interest expense		(19,177	)		(12,360	)		(6,817	)		55	%
Cost of debt retirement		(760	)		—			(760	)		N/A
Other expense		(118	)		(189	)		71			(38	)%
Equity in income (loss) of pipelines and gathering system ventures		(311	)		8,593			(8,904	)		(104	)%
Total	$	(56,945	)	$	(370	)	$	(56,575	)		15,291	%

Gain (loss) on derivatives not classified as hedges

     We recorded a loss of $36.8 million in 2007 for derivatives not classified as hedges as compared to a gain of $2.8 million for 2006. The greatest impact of the change in fair market valuation was within our crude oil contracts due to the significant increase in oil prices during 2007. We settled in cash a net of $16.6 million in derivative contracts during the year.

     The ineffective portion of our hedges was a gain of approximately $626,000 in 2006. As of December 31, 2006, all cash flow hedge contracts as defined by SFAS 133 were settled.

Interest expense

     Interest expense increased in 2007 as the result of increased borrowings and an increase in our weighted average interest rate. Our bank debt decreased from $165.0 million to $60.0 million during 2007. However, interest expense increased $6.6 million as a result of our $150.0 million senior notes offering in July 2007 and an increase in the average interest rate on our revolving credit facility in 2007. Our weighted average interest rate increased to 8.92% from 8.33% for 2007 and 2006, respectively. Due to the issuance of our 10¹/4% senior notes, we expect that our average interest rate for 2008 will increase over the 2007 average.

     Capitalized interest on work in progress decreased interest expense by $423,000 in 2007, a decrease of $214,000 compared to 2006.

Cost of debt retirement

     Cost of debt retirement represent the write off of previously capitalized debt issuance costs associated with our Second Lien Term Loan that was retired with the proceeds of our senior notes offering.

Equity in income (loss) of pipelines and gathering system ventures

     Since 2004, we have invested in four pipelines and gathering system joint ventures. During 2006, the assets of two of these ventures were sold. As a result, we recognized our share of net gains on sale of $9.0 million in 2006.

     During 2006, we and two other unaffiliated parties formed a joint venture known as the Hagerman Gas Gathering System, which was formed for the purpose of constructing, owning and operating a gas gathering system in New Mexico.

     The loss associated with our equity investments totaled $311,000 in 2007 versus a gain of $8.6 million in 2006. The gains realized in 2006 were the result of the sale of our interests in two pipeline joint ventures. We did not sell any interests in pipeline joint ventures during 2007. In addition, the Hagerman Gas Gathering System in New Mexico was operational for the entire twelve months of 2007 versus a few months in 2006. During 2006 and the first nine months 2007, production levels and related transportation volumes were not sufficient for profitable operation of this system. This resulted in an increase in our equity loss for this investment of $601,000. We also received final payout settlements for the divestiture of our investments in West Fork Pipeline Company I and West Fork Pipeline Company V of $161,000 and $126,000 respectively in the fourth quarter of 2007.

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Income tax

     Income tax was a benefit of $3.3 million in 2007 compared to an expense of $13.9 million in 2006. Income tax expense for 2008 will be dependent on our earnings and is expected to be approximately 35% of income before income taxes.

     Included in the $3.3 million income tax benefit amount was a net state tax benefit of the $592,000. Prior to 2007, we had not recognized a tax credit for state net operating loss carryovers due to the uncertainty about their ultimate realization. However, with the State of Texas revising its state tax laws in 2007 and our election to utilize the credit, we recognized this credit as we now expect to realize this benefit over future periods. See Note 9 to the Consolidated Financial Statements.

Basic and diluted net income

     We had basic net income (loss) per share of $(0.12) and $0.73 and diluted net income (loss) per share of $(0.12) and $0.71 for 2007 and 2006, respectively. Basic weighted average common shares outstanding increased from approximately 35.9 million shares in 2006 to approximately 38.1 million shares in 2007. The increase was primarily due to our public offering of 3.0 million shares of common stock in December 2007 and the exercise of employee and nonemployee stock options during 2007.

Years Ended December 31, 2006 and December 31, 2005

     Our oil and natural gas revenues and production product mix are shown in the table below for the years ended December 31, 2006 and 2005.

     Oil and Gas Revenues

	Revenues(1)						Production
	2006			2005			2006			2005
Oil (Bbls)		58	%		54	%		51	%		61	%
Natural gas (M cf)		42	%		46	%		49	%		39	%
Total		100	%		100	%		100	%		100	%

(1) Includes hedge transactions.

     The following table sets forth certain information about our operating revenues for the periods indicated.

										Percent
	Year Ended December 31,						Increase			Increase
	2006			2005			(Decrease)			(Decrease)
	($ in thousands, except per unit data)
Production Volumes
Oil (Bbls)		1,137			923			214			23	%
Natural gas (M cf)		6,539			3,592			2,947			82	%
BOE		2,227			1,522			705			46	%
Sales Price
Oil (per Bbl)(1)	$	59.86		$	51.78		$	8.08			16	%
Natural gas (per M cf)(1)	$	6.19		$	8.54		$	(2.35	)		(28	)%
BOE price(1)	$	48.73		$	51.57		$	(2.84	)		(6	)%
BOE price(2)	$	43.56		$	43.46		$	0.10			0	%
Operating Revenues
Oil	$	68,076		$	47,800		$	20,276			42	%
Oil hedges		(11,512	)		(12,139	)		627			5	%
Natural gas		40,461			30,690			9,771			32	%
Natural gas hedges		—			(201	)		201			100	%
Total	$	97,025		$	66,150		$	30,875			47	%

(1)	Excludes hedge transactions.
(2)	Includes hedge transactions.

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Oil revenues

     Oil revenues, excluding hedges, increased $20.3 million, or 42%, for the year ended 2006, as compared to 2005. Oil production volumes increased 23%, which was attributable to our 2006 drilling program in the Harris San Andres field that we acquired in 2005 and early 2006, re-stimulations and additional drilling in the Fullerton San Andres field and our drilling program in the Carm-Ann/N. Means Queen and Diamond M Canyon Reef. The increase in oil production increased revenue approximately $12.8 million for 2006. Average realized wellhead crude oil prices increased $8.08 per Bbl, or 16%, to $59.86 per Bbl for 2006, compared to 2005. The increase in oil price increased revenue approximately $7.5 million for 2006.

Natural gas revenues

     Natural gas revenues, excluding hedges, increased $9.8 million, or 32%, for the year ended 2006, as compared to 2005. Natural gas production volumes increased 82% as a result of added production from drilling discoveries in our gulf coast area of south Texas, Fort Worth Basin Barnett Shale wells and initial production from our New Mexico Wolfcamp wells. The increase in natural gas volumes increased revenue approximately $18.2 million for 2006. Average realized wellhead natural gas prices decreased 28%, or $2.35 per Mcf, to $6.19 per Mcf. The decrease in natural gas prices had a negative effect on revenues of approximately $8.4 million for the year ended December 31, 2006.

Oil hedges

     The negative effect on oil revenues of oil hedges decreased approximately $600,000, or 5%, for 2006, as compared to 2005, because contracts settled in 2006 had relatively higher strike prices in relation to the related market price at settlement. On a BOE basis, the negative effects of hedges declined from $8.11 per BOE in 2005 compared to $5.17 per BOE in 2006.

     Costs and Expenses

							Percent
	Year Ended December 31,				Increase		Increase
	2006		2005		(Decrease)		(Decrease)
	($ in thousands)
Lease operating expense	$	16,819	$	9,947	$	6,872		69	%
Production taxes		5,577		4,102		1,475		36	%
General and administrative:		9,523		6,712		2,811		42	%
Depreciation, depletion and amortization		24,687		12,044		12,643		105	%
Total	$	56,606	$	32,805	$	23,801		73	%

Lease operating expense

     Lease operating expense increased 69%, or $6.9 million, compared to 2005. Fifty-three percent (53%) of our 2006 production was from our long-life oil assets located in our west Texas Fullerton, Carm-Ann, Diamond M and Harris properties. Our increase in lease operating expenses is due to mechanical, ad valorem and utility costs which increased our related lifting costs (excluding production taxes) to $7.55 per BOE in 2006, as compared to $6.54 per BOE in 2005. We experienced a 15% increase in our per BOE lifting costs primarily due to higher lifting costs associated with non-operated wells and newly acquired operated wells for the year ended December 31, 2006.

Production taxes

     Production taxes increased 36%, or $1.5, million in 2006, which was associated with an increase in revenues of $30.0 million. Production taxes in future periods will continue to be a function of product mix, production volumes and product prices.

General and administrative

     Total general and administrative expenses increased 42%, or $2.8 million, in 2006 over 2005. During the second quarter of 2006, we determined that stock options to purchase 30,000 shares of common stock had been granted in 2003 to four of our employees under our 1998 Stock Option Plan, but which were not available for issuance under the plan. In June 2006, the Board of Directors authorized us to enter into settlement and release agree–

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ments with the four employees. Under these agreements, we made a one-time lump sum cash payment to each employee in an amount equal to the “spread” between the exercise price of the options and the closing price of our stock on June 21, 2006. The total cash payments were approximately $511,000. This amount was charged to general and administrative expense during the second quarter of 2006. Increased public reporting costs included, but were not limited to, increases in road show expenses, corporate counseling and oil and natural gas reserve analysis also contributed to the overall increases in general and administrative costs. In addition, we incurred additional public reporting costs associated with the stock options granted to our board of directors in late 2005. General and administrative expenses capitalized to the full cost pool were $1.7 million for 2006, compared to $1.3 million for 2005.

Depreciation, depletion and amortization

     Depreciation, depletion and amortization expense increased 105%, or $12.6 million, for 2006 compared to 2005. Depletion per BOE was $10.88 for 2006 and $7.61 for 2005. This increase is attributable to recent increases in overall drilling and related oilfield service costs and the costs of property acquisitions. Increased cost levels affect both the depletable amounts of capitalized costs in recent periods and the depletion attributable to amounts of estimated future development costs on proved undeveloped properties. In addition, our drilling efforts in 2006 were, and our future drilling plans are, focused on our natural gas resource projects which have higher associated per BOE drilling and development costs than our drilling projects in the Permian Basin of west Texas and onshore gulf coast of south Texas due to the use of horizontal drilling and multi-stage stimulation techniques. These factors, when combined with the increase in the absolute level of our capital expenditures during the recent period, have led to a significant increase in our depletion rate per BOE. Our annual costs incurred in the acquisition of, exploration for and development of oil and natural gas properties have increased by approximately 188% since 2004.

     Other income (expense)

										Percent
	Year Ended December 31,						Increase			Increase
	2006			2005			(Decrease)			(Decrease)
	($ in thousands)
Gain (loss) on derivatives not classified as hedges	$	2,802		$	(31,669	)	$	34,471			109	%
Gain (loss) on ineffective portion of hedges		626			(137	)		763			557	%
Interest and other income		158			167			(9	)		5	%
Interest expense		(12,360	)		(4,780	)		(7,580	)		(159	)%
Other expense		(189	)		(102	)		(87	)		(85	)%
Equity in income (loss) of pipelines and gathering system ventures		8,593			(89	)		8,682			9,755	%
Total	$	(370	)	$	(36,610	)	$	36,240			99	%

Gain (loss) on derivatives not classified as hedges

     We recorded a gain of $2.8 million in 2006 for derivatives not classified as hedges in 2006, as compared to a loss of $31.7 million for 2005. Future gains or losses on derivatives not classified as hedges will be impacted by the volatility of commodity prices and interest rates, as well as by the terms of any new derivative contracts.

     The ineffective portion of our hedges was a gain of approximately $626,000 in 2006, as compared to a loss of approximately $137,000 in 2005. As of December 31, 2006, all cash flow hedge contracts as defined by SFAS 133 were settled.

Interest expense

     Interest expense increased with the increase in our bank debt from $100.0 million to $165.0 million in 2006, along with an increase of our average loan interest rate from 7.96% to 8.30% in 2006. Interest expense will increase for 2007 with increased borrowings for leasehold acquisitions and amounts expended for drilling.

Equity in income (loss) of pipelines and gathering system ventures

     We invested in four pipelines and gathering system joint ventures beginning in 2004. During 2006, the assets of two of these ventures were sold. As a result, we recognized our share of net gains on sale of $9.0 million in 2006.

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Income tax

     We had an income tax expense of $13.9 million in 2006, compared to a $1.7 million income tax benefit in 2005. The income tax rate for 2007 will be dependent on our earnings and is expected to be approximately 35% of income before income taxes.

Basic and diluted net income

     We had basic and diluted net earnings per share of $0.73 and $0.71, respectively, for 2006 and basic and diluted net loss per share of $0.06 for 2005. Basic weighted average common shares outstanding increased from 32.3 million shares in 2005 to 35.9 million shares in 2006. Diluted weighted average common shares increased from 32.3 million shares in 2005 to 36.8 million shares in 2006. The increase in common shares was primarily due to our public offering of 2.5 million shares of common stock in August 2006.

Capital Resources and Liquidity

     Our capital resources consist primarily of cash flows from our oil and natural gas properties, borrowings supported by our oil and natural gas reserves and equity offerings. Our level of earnings and cash flows depends on many factors, including the prices we receive for oil and natural gas we produce.

     Working capital decreased approximately $24.5 million as of December 31, 2007 compared with December 31, 2006. Current liabilities exceeded current assets by $33.2 at December 31, 2007. The working capital decrease was primarily due to the increase in obligations associated with crude oil derivative contracts. In addition, our accounts payables have increased since last year as we have increased our drilling activity in the Barnett Shale area and due to the timing of payment of accrued interest associated with our senior notes.

     The following table summarizes our cash flows from operating, investing and financing activities:

	Year ended December 31,
	2007			2006			2005
	($ in thousands)
Operating activities	$	76,619		$	74,186		$	37,118
Investing activities	$	(167,397	)	$	(200,548	)	$	(84,949	)
Financing activities	$	92,684		$	125,854		$	49,468

     Cash provided from operating activities in 2007 increased $2.4 million over 2006 largely due to increased operating income which was offset partially with reductions in return on investment in pipelines and gathering system ventures.

     Cash used in investing activities decreased in 2007 compared to 2006, primarily as a result of the completion of the Harris field acquisition at the start of 2006.

     Cash provided by financing activities decreased in 2007 compared to 2006. This is a result of increased cash flow provided in operations and a decrease in cash used in investing activities in 2007. The result of these two factors allowed the company to reduce its financing activities in 2007.

     Historically, we have funded our operations, capital requirements and interest expense requirements with cash flows from our oil and natural gas properties, borrowings and proceeds from sales of our equity securities. Although we expect these same capital resources to support our future activities, we continually review and consider alternative methods of financing.

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     Senior Notes Offering

     On July 31, 2007, we completed a private offering of unsecured senior notes in the principal amount of $150.0 million. The net proceeds, after payment of typical transaction expenses, of the senior notes of approximately $143.5 million were used first to retire all of our indebtedness under our Second Lien Term Loan Agreement, with the remainder being applied to the repayment of indebtedness under our revolving credit facility.

     Shelf Registration Statement; Common Stock Offering

     On November 6, 2007, the United States Securities and Exchange Commission declared effective a shelf registration statement on Form S-3 filed by us to register $250.0 million of securities for potential future issuance.

     On December 6, 2007, we sold 3,000,000 shares of common stock in a public offering for net proceeds of approximately $52.5 million. We used the net proceeds for general corporate purposes and for conducting our exploitation, development and acquisition activities in certain core areas such as our Permian Basin properties and our Barnett Shale gas project. The proceeds were not deployed all at once. Pending such use, we used the net proceeds to repay borrowings under our revolving credit facility. We anticipate that the net proceeds will be available under our revolving credit facility as needed in the future to finance our exploitation, development and acquisition activities, subject to our compliance with provisions of our revolving credit facility that are conditions to loans and funding under our revolving credit facility and any recalculation of our borrowing base.

     The available balance of our $250.0 million universal shelf registration statement was $194.5 million as of December 31, 2007.

     In the future, we may, in one or more offerings, offer and sell debt securities and additional equity securities under our shelf registration statement.

     Revolving Credit Facility

     Our Third Amended and Restated Credit Agreement, or the “Revolving Credit Agreement”, with a group of bank lenders provides us with a revolving line of credit having a “borrowing base” limitation of $200.0 million at December 31, 2007. The total amount that we can borrow and have outstanding at any one time is limited to the lesser of $350.0 million or the borrowing base established by the lenders. At December 31, 2007, the principal amount outstanding under our revolving credit facility was $60.0 million, excluding $445,000 reserved for our letters of credit. We have pledged substantially all of our producing and natural gas properties to secure the repayment of our indebtedness under the Revolving Credit Agreement.

     The Revolving Credit Agreement allows us to borrow, repay and reborrow amounts available under the revolving credit facility. The amount of the borrowing base is based primarily upon the estimated value of our oil and natural gas reserves. The borrowing base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each year or at other times required by the lenders or at our request. If, as a result of the lenders’ redetermination of the borrowing base, the outstanding principal amount of our loans exceeds the borrowing base, we must either provide additional collateral to the lenders or repay the outstanding principal of our loans in an amount equal to the excess. Except for the principal payments that may be required because of our outstanding loans being in excess of the borrowing base, interest only is payable monthly.

     Loans made to us under this revolving credit facility bear interest at the base rate of Citibank, N.A. or the “LIBOR” rate, at our election. Generally, Citibank’s base rate is equal to its “prime rate” as announced from time to time by Citibank.

     The LIBOR rate is generally equal to the sum of (a) the rate designated as “British Bankers Association Interest Settlement Rates” and offered in one, two, three, six or twelve month interest periods for deposits of $1.0 million, and (b) a margin ranging from 2.00% to 2.50%, depending upon the outstanding principal amount of our loans. If the principal amount outstanding is equal to or greater than 75% of the borrowing base, the margin is 2.50%. If the principal amount outstanding is equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.25%. If the principal amount outstanding is less than 50% of the borrowing base, the margin is 2.00%.

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     The interest rate we are required to pay on our borrowings, including the applicable margin, may never be less than 5.00%. At December 31, 2007, our weighted average base rate and LIBOR rate, plus the applicable margin, was 6.84% on $60.0 million, the outstanding principal amount of our revolving loan on that same date.

     In the case of base rate loans, interest is payable on the last day of each month. In the case of LIBOR loans, interest is payable on the last day of each applicable interest period.

     If the total outstanding borrowings under the revolving credit facility are less than the borrowing base, we are required to pay an unused commitment fee to the lenders in an amount equal to .25% of the daily average of the unadvanced portion of the borrowing base. The fee is payable quarterly.

     If the borrowing base is increased, we are also required to pay a fee of .375% on the amount of any such increase.

     All outstanding principal and accrued and unpaid interest under the revolving credit facility is due and payable on October 31, 2010. The maturity date of our outstanding loans may be accelerated by the lenders upon the occurrence of an event of default under the Revolving Credit Agreement.

     The Revolving Credit Agreement presently contains financial covenants and other restrictions, some of which prohibit us from:

• creating, incurring, assuming or permitting to exist any lien, security interest or other encumbrance on any of our assets or properties, except specified permitted liens;

• selling, leasing, transferring or otherwise disposing of any of our assets, except (a) extracted petroleum hydrocarbons sold in the ordinary course of our business; (b) worthless or obsolete equipment, and interests in oil and natural gas leases, or portions thereof, not capable of being held by production of oil, natural gas or other hydrocarbons or minerals in commercial quantities; and (c) transfers to us or any subsidiary;

• allowing our current ratio (as adjusted for available borrowing and unrealized derivative losses) to be less than 1.0 to 1.0 as of the end of any fiscal quarter;

• allowing our ratio of consolidated funded debt to consolidated EBITDA for any fiscal quarter (calculated at the end of each fiscal quarter using the results of the immediately preceding twelve-month period) to exceed (a) 4.25 to 1.00 during 2007, (b) 4.00 to 1.00 during 2008, or (c) 3.50 to 1.00 during 2009 and thereafter;

• allowing our adjusted consolidated net worth to be less than the sum of (a) $85.0 million, plus (b) 75% of the net proceeds from the sale of any equity securities, plus (c) 50% of our consolidated net income for each fiscal quarter determined on a cumulative basis from September 30, 2005;

• forming any new subsidiary or consolidating or merging with or into any other entity, except for certain intra-company consolidations or mergers where we are the surviving entity;

• becoming liable in respect of any indebtedness, or guaranteeing or otherwise in any manner becoming liable for indebtedness or obligations of any other person, except for (a) indebtedness incurred in connection with our revolving credit facility; (b) taxes, assessments and government charges; (c) obligations arising out of interest rate management transactions permitted under our revolving credit facility; (d) indebtedness evidenced by our 10¹/4% senior notes due 2014 not to exceed the aggregate principal amount of $150.0 million; (e) indebtedness incurred in the ordinary course of business that is not more than 60 days past due; or (f) other indebtedness not exceeding $1,000,000 in the aggregate;

• declaring, paying or making any loans, advances, distributions or dividends to our equity owners, or acquiring, redeeming or retiring any stock or other security issued by us, except for certain purchases of the notes and certain intra-company dividends or distributions from our subsidiaries to us;

(46)

• making or permitting to remain outstanding any loans or advances to any person or entity, except (a) advances made in the ordinary course of our business; (b) other loans or advances to a third party not to exceed $1.0 million in the aggregate; or (c) intra-company loans;

• discounting, or selling with recourse, or selling for less than market value, any of our notes receivable or accounts receivable;

• permitting any material change in the character of our business;

• entering into transactions with our affiliates, except transactions upon terms that are no less favorable than could be obtained in a transaction negotiated at arm’s length with an unrelated third party;

• entering into commodity hedging or interest rate management transactions, except transactions required by our revolving credit facility, consented to by our lenders, or transactions designed to hedge, provide a floor price for, or swap crude oil or natural gas, provided certain conditions are satisfied;

• making any investments in any entity, except (a) investments with maturities of not more than 180 days in direct obligations of the United States of America or any agency thereof; (b) investments in certain certificates of deposits; (c) our existing investments at December 23, 2005; (d) other investments not to exceed $10.0 million in the aggregate when aggregated with loans and advances permitted to be made or remain outstanding under our revolving credit facility during 2007 and $1.0 million in the aggregate when aggregated with other permitted loans and advances for calendar years after 2007; (e) investments in certain certificates of deposit not to exceed $50,000; or (f) investments in any subsidiary;

• permitting any material amendment to our organizational or governing documents;

• permitting any plan subject to ERISA to (a) engage in any “prohibited transaction” as such term is defined in Section 4975 of the Internal Revenue Code of 1986, as amended; (b) incur any “accumulated funding deficiency” as such term is defined in Section 302 of ERISA; or (c) terminate in a manner which could result in the imposition of a lien on its property pursuant to Section 4068 of ERISA;

• permitting any change in accounting method or fiscal year;

• allowing our subsidiaries to issue or sell to any third party any equity interest in them, or any option, warrant or other right to acquire any such equity interest;

• making any amendment or entering into any agreement to amend or otherwise change the Indenture governing our 10¹/4% senior notes due 2014, failing to comply with the terms of the Indenture, or, except as specifically required by the Indenture, making any prepayment of amounts owing under such notes; or

• permitting or incurring any lease obligations which would cause the aggregate amount of all payments pursuant to all such leases to exceed $1,000,000 in any twelve month period during the life of such leases, except for oil and gas related leases.

     As of December 31, 2007 we were in compliance with all of the covenants in our Revolving Credit Agreement.

     Second Lien Term Loan Facility

     Until July 31, 2007, we also had a $50.0 million term loan available to us under our Second Lien Term Loan Agreement, or the “Second Lien Agreement”. Similar to our Revolving Credit Agreement, interest on loans made to us under this credit facility were, at our election, either an alternate base rate or a rate designated in the Second Lien Agreement as the “LIBO” rate. The alternate base rate was the greater of (a) the prime rate in effect on any day and (b) the “Federal Funds Effective Rate” in effect on such day plus -1/2 of 1%, plus a margin of 3.50% per annum.

(47)

     The LIBO rate was generally equal to the sum of (a) a rate appearing in the Dow Jones Market Service for the applicable interest periods offered in one, two, three or six month periods and (b) an applicable margin rate per annum equal to 4.50%.

     Our producing oil and natural gas properties were also pledged to secure payment of our indebtedness under this facility, but the liens granted to the lenders under the Second Lien Agreement were second and junior to the rights of the lienholders under the Revolving Credit Agreement.

     In the case of alternate base rate loans, interest was payable the last day of each March, June, September and December. In the case of LIBO loans, interest was payable the last day of the interest period applicable to each tranche, but not to exceed intervals of three months.

     Upon completion of our senior notes offering, described below, we paid off and terminated this facility with $50.2 million of the net proceeds from the offering. As a result we charged to earnings $760,000 of previously capitalized debt issuance cost.

     Senior Notes

     Purchase Agreement. On July 26, 2007, we entered into a Purchase Agreement among us and Jefferies & Company, Inc., Merrill, Lynch Pierce Fenner and Smith Incorporated and BNP Paribas Securities Corp., or the “Initial Purchasers”, relating to the sale and issuance of $150.0 million principal amount of 10 ¹/4% Senior Notes due 2014, or the “senior notes”. The Purchase Agreement contains customary representations and warranties of the parties and indemnification and contribution provisions. The Initial Purchasers or their respective affiliates have provided, and may in the future from time to time provide, financial advisory, investment banking or commercial banking services to us or our affiliates, for which they have received, and we expect will receive, customary fees. In particular, an affiliate of BNP Paribas Securities Corp. acts as agent and lender under our revolving credit facility and, prior to its termination, our second lien term loan facility, and has received and will continue to receive fees for their services.

     On July 31, 2007, we completed the private offering of the senior notes in the principal amount of $150.0 million. The senior notes were recorded at the principal amount net of underwriters discount and related expenses of $4.8 million.

     Indenture. On July 31, 2007, we issued the senior notes pursuant to an Indenture dated July 31, 2007 between us and Wells Fargo Bank, National Association, as Trustee in a transaction exempt from the registration requirements under the Securities Act of 1933, or the “Securities Act”. The senior notes were sold within the United States only to qualified institutional buyers in reliance on Rule 144A under the Securities Act and to Institutional Accredited Investors pursuant to Rule 501(a)(1), (2), (3) or (7) under the Securities Act.

     We used the net proceeds from the issuance to repay outstanding indebtedness under our existing Revolving Credit Agreement and Second Lien Agreement.

     Interest on the senior notes of 10 ¹/4% per annum on the principal amount of the senior notes is payable semi-annually on February 1 and August 1 of each year to holders of record at the close of business on the preceding January 15 and July 15, respectively, commencing on February 1, 2008. Considering the discount on the senior notes, the effective interest rate is 10.92%. The senior notes will mature on August 1, 2014. The senior notes are our unsecured senior obligations and rank equally in right of payment with all of our existing and future senior indebtedness and are effectively subordinated in right of payment to all of our existing and future secured indebtedness, including debt of our senior credit agreement.

     On or after August 1, 2011, we may redeem all or a part of the senior notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest on the senior notes, if any, to the applicable redemption date, if redeemed during the 12-month period beginning August 1 of the years indicated:

Year	Redemption Price
2011		105.125	%
2012		102.563	%
2013		100.000	%

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     Prior to August 1, 2010, we may on one or more occasions redeem up to an aggregate amount equal to 35% of the aggregate principal amount of the senior notes, at a redemption price of 110.25% of the principal amount of the senior notes, plus accrued and unpaid interest, if any, to the redemption date, with the net cash proceeds of one or more equity offerings; provided, that (i) at least 65% in aggregate principal amount of the senior notes originally issued remains outstanding immediately after the occurrence of such redemption (excluding senior notes held by us or any of our subsidiaries) and (ii) each such redemption occurs within 90 days of the date of the closing of the related equity offering.

     In addition, at any time prior to August 1, 2011, we may redeem all or part of the senior notes at a redemption price equal to:

     (i) 100% of the principal amount thereof, plus

     (ii) a “make-whole” premium, and accrued and unpaid interest, if any, to, the redemption date. Generally, the “make-whole” premium is an amount equal to the greater of (a) 1% of the principal amount of the senior notes being redeemed and (b) the excess of the present value of the redemption price of such notes as of August 1, 2011 plus all required interest payments due through August 1, 2011 (computed at a discount rate equal to a specified U.S. “Treasury Rate” plus 50 basis points), over the principal amount of the senior notes being redeemed.

     If we experience a change of control, we will be required to make an offer to repurchase the senior notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase. Generally, a “change of control” means:

• the sale or other disposition of all or substantially all of our assets;

• the adoption by the Board of Directors of a plan of liquidation or dissolution;

• any person becomes the owner of more than 50% of our voting stock;

• the first day on which a majority of the members of the Board of Directors of Parallel are not continuing directors; or

• certain mergers and consolidations with or into any other person.

     Upon an event of default, the Trustee or the holders of at least 25% in principal amount of the outstanding senior notes may declare the entire principal of, premium, if any, accrued and unpaid interest, if any, and liquidated damages, if any, on all the senior notes to be due and payable immediately. Subject to certain qualifications, an “event of default” includes, generally:

• default for 30 days in the payment when due of interest on the senior notes;

• default in the payment when due of the principal of the senior notes;

• our failure to comply with the covenants or agreements in the Indenture;

• defaults on indebtedness under other mortgages, indentures or instruments which results from our failure to pay the principal or interest on such indebtedness or which results in the acceleration of such indebtedness prior to its maturity and the principal amount of any such indebtedness aggregates $10.0 million or more;

• our failure to pay final judgments in excess of $10.0 million;

• any subsidiary guarantee is held in any judicial proceeding to be unenforceable or invalid; and

• certain events of bankruptcy or insolvency with respect to us or certain of our subsidiaries.

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     Subject to certain exceptions and qualifications, the Indenture restricts our ability and any future subsidiaries to:

• transfer or sell assets;

• make investments;

• pay dividends, redeem subordinated indebtedness or make other restricted payments;

• incur or guarantee additional indebtedness or issue disqualified capital stock;

• create or incur liens;

• incur dividend or other payment restrictions affecting certain subsidiaries;

• consummate a merger, consolidation or sale of all or substantially all of our assets;

• enter into transactions with affiliates; and

• engage in businesses other than the oil and gas business.

     Registration Rights Agreement. On July 31, 2007, we also entered into a Registration Rights Agreement with the Initial Purchasers relating to the senior notes. We agreed to use our commercially reasonable efforts to prepare and, not later than 180 days after the date of original issue of the senior notes, file an exchange offer registration statement with the Securities and Exchange Commission with respect to an offer to exchange the senior notes for substantially identical notes that are registered under the Securities Act. We filed an exchange offer registration statement with the SEC on January 4, 2008. We also agreed to use our reasonable best efforts to have such registration statement declared effective by the SEC within 210 days after July 31, 2007. The registration statement became effective on January 29, 2008. Additionally, we further agreed to promptly commence the exchange offer after such registration statement is declared effective by the SEC and to keep such exchange offer open for at least 20 business days after notice is mailed to the holders of the senior notes. We also agreed to use our reasonable best efforts to keep the exchange offer registration statement effective and to amend and supplement the prospectus contained therein.

     If we fail to meet certain specified registration obligations applicable to the senior notes, then additional interest will accrue over and above the interest set forth in the senior notes from and including the date on which any such registration default occurs but excluding the date on which all such registration defaults have been cured. The rate of the additional interest will be 0.25% per year for the first 90-day period immediately following the occurrence of a registration default, and such rate will increase by an additional 0.25% per year with respect to each subsequent 90-day period until all registration defaults have been cured, up to a maximum additional interest rate of 1.0% per year.

Preferred Stock

     At January 1, 2005 we had 950,000 shares of 6% convertible preferred stock outstanding. The preferred stock:

• required us to pay dividends of $.60 per annum, semi-annually on June 15 and December 15 of each year;

• was convertible into common stock at any time, at the option of the holder, into 2.8751 shares of common stock at an initial conversion price of $3.50 per share, subject to adjustment in certain events;

• was redeemable at our option, in whole or in part, for $10 per share, plus accrued dividends;

• had no voting rights, except as required by applicable law;

• was senior to the common stock with respect to dividends and on liquidation, dissolution or winding up of Parallel; and

• had a liquidation value of $10 per share, plus accrued and unpaid dividends.

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     As of June 6, 2005, all 950,000 outstanding shares of 6% convertible preferred stock had been converted into 2,714,280 shares of common stock.

Commodity Price Risk Management Transactions and Effects of Derivative Instruments

     The purpose of our derivative transactions is to provide a measure of stability in our cash flows. The derivative trade arrangements we have employed include collars, costless collars, floors or purchased puts, and oil, natural gas and interest rate swaps. In 2003, we designated our derivative trades as cash flow hedges under the provisions of SFAS 133, as amended. Although our purpose for entering into derivative trades has remained the same, contracts entered into after June 30, 2004 have not been designated as cash flow hedges.

     At December 31, 2006, we had no derivatives in place that were designated as cash flow hedges. All commodity derivative contracts at December 31, 2007 are accounted for by “mark-to-market” accounting whereby changes in fair value are charged to earnings. Changes in the fair values of derivatives are recorded in our Consolidated Statements of Operations as these changes occur in the “Other income (expense), net”. To the extent these trades relate to production in 2008 and beyond, and oil prices increase, we will report a loss currently, but if there is no further change in prices, our revenue will be correspondingly higher (than if there had been no price increase) when the production is sold.

     All interest rate swaps that we have entered into for 2007 and beyond are accounted for by “mark-to-market” accounting as prescribed in SFAS 133.

     We are exposed to credit risk in the event of nonperformance by the counterparties to our derivative trade instruments. However, we periodically assess the creditworthiness of the counterparties to mitigate this credit risk.

     For additional information about our price risk management transactions, see Item. 7A of this Annual Report on Form 10-K, beginning on page 54.

Future Capital Requirements

     Our capital expenditure budget for 2008 is approximately $127.2 million and is highly dependent on future oil and natural gas prices and the availability of funding. The timing of most of our capital expenditures is discretionary because we have not made any significant long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures according to market conditions. In addition to the impact that oil and natural gas prices will have on our budget, these expenditures will also be subject to:

• our internally generated cash flows;

• the availability of additional borrowings under our revolving credit facility or from other sources;

• the availability of supplies and services;

• additional sources of funding; and

• our future drilling successes.

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Contractual Obligations, Commitments and Off-Balance Sheet Arrangements

     We have contractual obligations and commitments that may affect our financial condition. The following table is a summary of our significant contractual obligations:

	Obligation Due in Period
Contractual Cash Obligations	2008		2009		2010		2011		2012		After 5 years		Total
							($ in thousands)
Revolving Credit Facility (secured)	$	4,117	$	4,106	$	63,419	$	—	$	—	$	—	$	71,642
Senior Notes (unsecured)		15,418		15,375		15,375		15,375		15,375		180,750		257,668
Office Lease (Dinero Plaza)		200		200		33		—		—		—		433
Snyder Field Offices (1)		14		14		14		14		14		521		591
Asset Retirement Obligations(2)		598		92		127		85		17		4,018		4,937
Derivative Obligations		30,424		7,600		5,594		—		—		—		43,618
Total	$	50,771	$	27,387	$	84,562	$	15,474	$	15,406	$	185,289	$	378,889

(1)	The Snyder office lease expires upon the cessation of production from the Diamond “M” area wells. The lease cost for the office facility is billed to nonaffiliated third party working interest owners under our joint operating agreements with these third parties.
(2)	Asset retirement obligations of oil and natural gas assets, excluding salvage value and accretion.

     Deferred taxes are not included in the table above. The utilization of net operating loss carryforwards combined with our plans for development and acquisitions may offset any major cash outflows. However, the ultimate timing of the settlements cannot be precisely determined.

     The amounts above include principal payment obligations under the revolving credit facility and senior notes noted in the table above, and interest payments on such indebtedness. See Note 8 to the Consolidated Financial Statements.

     We have no off-balance sheet financing arrangements or any unconsolidated special purpose entities.

Outlook

     The oil and natural gas industry is capital intensive. We make, and anticipate that we will continue to make, substantial capital expenditures in the exploration for, development and acquisition of oil and natural gas reserves. Historically, our capital expenditures have been financed primarily with:

• internally generated cash from operations;

• proceeds from bank borrowings; and

• proceeds from sales of equity securities.

     The continued availability of these capital sources depends upon a number of variables, including:

• our proved reserves;

• the volumes of oil and natural gas we produce from existing wells;

• the prices at which we sell oil and natural gas; and

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

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     Each of these variables materially affects our borrowing capacity. We may from time to time seek additional financing in the form of:

• increased bank borrowings;

• sales of our debt and equity securities;

• sales of non-core properties; and

• other forms of financing.

     Except for our existing revolving credit facility, we do not have any agreements for future financing and there can be no assurance as to the availability or terms of any such financing.

Inflation

     Our drilling costs have escalated and we would expect this trend to continue. However, over the past several years our commodity prices have increased to offset the effects of cost inflation.

Recent Accounting Pronouncements

     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“FAS 157”). FAS 157 defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosure requirements related to the use of fair value measures in financial statements. FAS 157 will be effective for our financial statements for the fiscal year beginning January 1, 2008; however, earlier application is encouraged. We are currently evaluating the impact that adoption might have on our financial position or results of operations, although we do not expect any impact to be significant.

     In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of FASB Statement No. 115,” (“FAS 159”) which will become effective on January 1, 2008. FAS 159 permits entities to measure eligible financial assets, financial liabilities and firm commitments at fair value, on an instrument-by-instrument basis, that are otherwise not permitted to be accounted for at fair value under other generally accepted accounting principles. The fair value measurement election is irrevocable and subsequent changes in fair value must be recorded in earnings. We will adopt this statement in the first quarter of 2008 and we do not expect to elect the fair value option for any eligible financial instruments and other items.

     In April 2007, the FASB issued FASB Staff Position FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”). FSP FIN 39-1 clarifies that a reporting entity that is party to a master netting arrangement can offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement. FSP FIN 39-1 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Adoption of FSP FIN 39-1 is not expected to have a material impact on our consolidated financial statements.

     In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non- controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008, which will be the company’s fiscal year 2009. The impact, if any, will depend on the nature and size of business combinations that Parallel consummates after the effective date.

     In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities

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that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008, which will be our fiscal year 2009. Based upon the December 31, 2007 balance sheet, the statement would have no impact.

Critical Accounting Policies

     Our critical accounting policies are included and discussed in Note 1 to our Consolidated Financial Statements as of December 31, 2007 and 2006 and for the three years ended December 31, 2007 included elsewhere herein. These critical accounting policies should be read in conjunction with the Consolidated Financial Statements and the accompanying Notes.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     The following quantitative and qualitative information is provided about market risks and our derivative instruments at December 31, 2007 from which we may incur future earnings, gains or losses from changes in market interest rates and oil and natural gas prices.

Interest Rate Sensitivity as of December 31, 2007

     Our only Financial instruments sensitive to changes in interest rates are our senior notes, bank debt and interest rate swaps. The table below shows principal cash flows and related interest rates by expected maturity dates. Interest rates were determined using our interest rate at December 31, 2007. You should read Note 8 to the Consolidated Financial Statements for further discussion of our debt that is sensitive to interest rates.

													2011 and
	2007			2008			2009			2010			after			Total
							($ in thousands)
Revolving Credit Facility (secured)	$	—		$	—		$	—		$	60,000		$	—		$	60,000
Interest rate		6.84	%		6.84	%		6.84	%		6.84	%		—
Senior notes	$	—		$	—		$	—		$	—		$	150,000		$	150,000
Interest rate		10.25	%		10.25	%		10.25	%		10.25	%		10.25	%

     At December 31, 2007, we had outstanding bank loans in the aggregate principal amount of $60.0 million at an interest rate of 6.84%. Under our revolving credit facility, we may elect an interest rate based upon the agent bank’s base lending rate or the LIBOR rate, plus a margin ranging from 2.00% to 2.50% per annum, depending on our borrowing base usage. The interest rate we are required to pay, including the applicable margin, may never be less than 5.00%. As the interest rate is variable and reflects current market conditions, the carrying value of our bank debt approximates the fair value.

     At December 31, 2007, we had outstanding senior notes in the aggregate principal amount of $150.0 million bearing interest at a rate of 10.25% per annum. The carrying value of our 10.25% senior notes at December 31, 2007 is approximately $145.4 million and their estimated fair value is approximately $150.0 million. Fair value is estimated based on market trades at or near December 31, 2007. Interest on our senior notes and their carrying value are not affected by changes in interest rates. However, the fair value of the senior notes increases as interest rates decrease and their fair value decreases as interest rates increase. Because we have no present plan or intent to redeem the senior notes, changes in their fair value are not expected to have any effect on our cash flow in the foreseeable future.

     As of December 31, 2007, we employed fixed interest rate swap contracts with BNP Paribas and Citibank, NA based on the 90-day LIBOR rates at the time of the contracts. These contracts are accounted for by “mark to market” accounting as prescribed in SFAS 133. We receive interest based on a 90-day LIBOR rate and pay the fixed rates shown below. We view these contracts as protection against future interest rate volatility.

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     Below is a table describing the nature of these interest rate swaps and the fair market value of these contracts as of December 31, 2007.

						Estimated
	Notional		Weighted Average			Fair Market Value
Period of Time	Amounts		Fixed Interest Rates			at December 31, 2007
	($ in millions)					($ in thousands)
January 1, 2008 thru December 31, 2008	$	100		4.86	%	$	(800	)
January 1, 2009 thru December 31, 2009	$	50		5.06	%		(754	)
January 1, 2010 thru October 31, 2010	$	50		5.15	%		(441	)
Total Fair Market Value						$	(1,995	)

Commodity Price Sensitivity as of December 31, 2007

     Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce natural gas. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue. Oil prices we received during 2007 ranged from a low of $47.62 per barrel to a high of $95.93 per barrel. Natural gas prices we received during 2007 ranged from a low of $1.37 per Mcf to a high of $16.09 per Mcf. A significant decline in the prices of oil or natural gas could have a material adverse effect on our financial condition and results of operations.

     We use various derivative instruments to minimize our exposure to the volatility of commodity prices. As of December 31, 2007, we had employed commodity collars and swaps in order to protect against this price volatility. Although all of the contracts that we have entered into are viewed as protection against this price volatility, all contracts are accounted for by the “mark to market” accounting method as prescribed in SFAS 133.

     Below is a description of our active commodity contracts as of December 31, 2007.

     Collars. Collars are contracts which combine both a put option, or “floor”, and a call option, or “ceiling”. These contracts may not involve payment or receipt of cash at inception, depending upon “ceiling” and “floor” strike prices.

     A summary of our collar positions at December 31, 2007 is as follows:

							Estimated
	Barrles of		NYMEX Oil Prices				Fair Market
Period of Time	Oil		Floor		Cap		Value
							($ in thousands)
January 1, 2008 thru December 31, 2008		347,700	$	63.42	$	83.86	$	(4,003	)
January 1, 2009 thru December 31, 2009		620,500	$	63.53	$	80.21		(6,846	)
January 1, 2010 thru October 31, 2010		486,400	$	63.44	$	78.26		(5,153	)

	MMBtu of		WAHA Gas Prices
	Natural Gas		Floor		Cap
January 1, 2008 thru March 31, 2008		546,000	$	6.50	$	9.50		87
April 1, 2008 thru December 31, 2008		1,375,000	$	6.75	$	8.40		63
Total Fair Market Value							$	(15,852	)

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     Commodity Swaps. Generally, swaps are an agreement to buy or sell a specified commodity for delivery in the future, but at an agreed fixed price. Swap transactions convert a floating or market price into a fixed price. For any particular swap transaction, the counterparty is required to make a payment to us if the reference price for any settlement period is less than the swap or fixed price for the applicable derivative contract, and we are required to make a payment to the counterparty if the reference price for any settlement period is greater than the swap or fixed price for the applicable derivative contract.

     We have entered into oil swap contracts with BNP Paribas. A recap for the period of time, number of Bbls, and weighted average swap prices are as follows:

					Estimated
	Barrels of		NYMEX Oil		Fair Market
Period of Time	Oil		Swap Price		Value
					($ in thousands)
January 1, 2008 thru December 31, 2008		439,200	$	33.37	$	(25,621	)

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     Our Consolidated Financial Statements and supplementary financial data are included in this Annual Report on Form 10-K beginning on page F-1.

     We have prepared these financial statements in conformity with generally accepted accounting principles. We are responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary for us to make informed estimates and judgments based on currently available information on the effects of certain events and transactions.

     Our independent public accountants, BDO Seidman, LLP, are engaged to audit our financial statements and to express an opinion thereon. Their audit is conducted in accordance with auditing standards generally accepted in the United States to enable them to report whether the financial statements present fairly, in all material respects, our financial position and results of operations in accordance with accounting principles generally accepted in the United States.

     The Audit Committee of our Board of Directors is composed of four Directors who are not our employees. This committee meets periodically with our independent public accountants and management. Our independent public accountants have full and free access to the Audit Committee to meet, with and without management being present, to discuss the results of their audits and the quality of our financial reporting.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

     None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

     We use disclosure controls and procedures to help ensure that information we are required to disclose in reports that we file with the Securities and Exchange Commission is accumulated and communicated to our management and recorded, processed, summarized and reported within the time periods specified by the SEC. As of the end of the period covered by this Annual Report on Form 10-K, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended) was evaluated by our management, with the participation of Larry C. Oldham, our President and Chief Executive Officer (principal executive officer), and Steven D. Foster, our Chief Financial Officer (principal financial officer). Our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, our disclosure controls and procedures are effective for their intended purposes.

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Management’s Annual Report on Internal Control Over Financial Reporting

     Management of Parallel is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended.

     Our internal control over financial reporting is a process designed by, or under the supervision of, our principal executive and financial officers, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Our internal control over financial reporting includes those policies and procedures that:

• pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that our receipts and expenditures are being made only in accordance with authorizations of management and our Board of Directors; and,

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

     Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

     Management assessed the effectiveness of Parallel’s internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission. As a result of this assessment, management determined that Parallel’s internal control over financial reporting, as of December 31, 2007, was effective based on those criteria.

     BDO Seidman, LLP, the independent registered public accounting firm who also audited our Consolidated Financial Statements included in this Annual Report on Form 10-K, has issued an attestation report on our internal control over financial reporting as of December 31, 2007, which is set forth below under “Attestation Report”.

Changes in Internal Controls

     During the fourth quarter of fiscal 2007, there were no changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Attestation Report

Report of Independent Registered Public Accounting Firm
on Internal Control over Financial Reporting

Board of Directors and Shareholders
Parallel Petroleum
Midland, Texas

We have audited Parallel Petroleum Corporation’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Parallel Petroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Annual

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Report on Internal Control Over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Parallel Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Parallel Petroleum Corporation as of December 31, 2007 and 2006, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007 and our report dated February 20, 2008 expressed an unqualified opinion thereon.

BDO Seidman, LLP
Houston, Texas
February 20, 2008

ITEM 9B. OTHER INFORMATION

     None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

     Our Directors and executive officers at February 1, 2008 are as follows:

			Director
Name	Age		Since		Position with Company
Jeffrey G. Shrader(1)(2)(3)(4)		57		2001	Director and Chairman of the Board of Directors
Larry C. Oldham(1)		54		1979	Director, President and Chief Executive Officer
Donald E. Tiffin		50		—	Chief Operating Officer
Eric A. Bayley		59		—	Vice President of Corporate Engineering
John S. Rutherford		47		—	Vice President of Land and Administration
Steven D. Foster		52		—	Chief Financial Officer
Edward A. Nash(1)(2)(3)(4)		59		2007	Director
Martin B. Oring(1)(2)(3)(4)		62		2001	Director
Ray M. Poage(1)(2)(3)(4)		60		2003	Director

(1)	Member of Hedging and Acquisitions Committee
(2)	Member of Compensation Committee
(3)	Member of Audit Committee
(4)	Member of Corporate Governance and Nominating Committee

     Mr. Shrader has been a shareholder in the law firm of Sprouse Shrader Smith, Amarillo, Texas, since January 1993. He has also served as a director of Hastings Entertainment, Inc. since 1992. At February 1, 2008, Mr. Shrader was Chairman of the Corporate Governance and Nominating Committee of the Board of Directors.

     Mr. Oldham is a founder of Parallel and has served as an officer and Director since its formation in 1979. Mr. Oldham became President of Parallel in October 1994, and served as Executive Vice President before becoming President. Effective January 1, 2004, Mr. Oldham became Chief Executive Officer. Mr. Oldham received a Bachelor of Business Administration degree from West Texas State University in 1975.

     Mr. Tiffin served as Vice President of Business Development from June 2002 until January 1, 2004 when he became Chief Operating Officer. From August 1999 until May 2002, Mr. Tiffin served as General Manager of First Permian, L.P. and from July 1993 to July 1999, Mr. Tiffin was the Drilling and Production Manager in the Midland, Texas office of Fina Oil and Chemical Company. Mr. Tiffin graduated from the University of Oklahoma in 1979 with a Bachelor of Science degree in Petroleum Engineering.

     Mr. Bayley has been Vice President of Corporate Engineering since July 2001. From October 1993 until July 2001, Mr. Bayley was employed by Parallel as Manager of Engineering. From December 1990 to October 1993, Mr. Bayley was an independent consulting engineer and devoted substantially all of his time to Parallel. Mr. Bayley graduated from Texas A&M University in 1978 with a Bachelor of Science degree in Petroleum Engineering. He graduated from the University of Texas of the Permian Basin in 1984 with a Master’s of Business Administration degree.

     Mr. Rutherford has been Vice President of Land and Administration of Parallel since July 2001. From October 1993 until July 2001, Mr. Rutherford was employed as Manager of Land/Administration. From May 1991 to October 1993, Mr. Rutherford served as a consultant to Parallel, devoting substantially all of his time to Parallel’s

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business. Mr. Rutherford graduated from Oral Roberts University in 1982 with a degree in Education, and in 1986 he graduated from Baylor University with a Master’s degree in Business Administration.

     Mr. Foster has been the Chief Financial Officer of Parallel since June 2002. From November 2000 to May 2002, Mr. Foster was the Controller and Assistant Secretary of First Permian, L.P. and from September 1997 to November 2000, he was employed by Pioneer Natural Resources, USA in the capacities of Director of Revenue Accounting and Manager of Joint Interest Accounting. Mr. Foster graduated from Texas Tech University in 1977 with a Bachelor of Business Administration degree in Accounting. He is a certified public accountant.

     Mr. Nash served as a consultant to TOTAL Petrochemicals, Inc. from February 2004 until December 2006, providing advisory services primarily in the areas of corporate relocation, construction, safety and communications. He also served as a consultant to Clayton Williams Energy, Inc. from September 2003 to September 2004, primarily in the area of acquisitions. From 2000 to March 2003, Mr. Nash was employed by TOTAL as a Senior Vice President of Special Projects and as Senior Vice President of its U.S. onshore division. From 1974 to 2000, Mr. Nash was employed by Fina, Inc. in various capacities, including serving as Vice President of Human Resources, Vice President Exploration and Production from April 1998 to 2000 and as President of Fina Natural Gas Company from 1999 to 2000. Mr. Nash graduated from Texas A&M University in 1970 with a Bachelors of Science degree in Mechanical Engineering. He is a registered professional engineer in Petroleum and Mechanical Engineering. At February 1, 2008, Mr. Nash was Chairman of the Compensation Committee.

     Mr. Oring is an owner and managing member of Wealth Preservation, LLC, a financial counseling firm founded by Mr. Oring in January 2001. From 1998 to December 2000, Mr. Oring was Managing Director Executive Services of Prudential Securities Incorporated, and from 1996 to 1998, Mr. Oring was Managing Director Capital Markets of Prudential Securities Incorporated. From 1989 to 1996, Mr. Oring was Manager of Capital Planning for The Chase Manhattan Corporation. Mr. Oring is also a director of PetroHunter Energy Corporation. At February 1, 2008, Mr. Oring was Chairman of the Hedging and Acquisitions Committee of the Board of Directors.

     Mr. Poage was a partner in KPMG LLP from 1980 to June 2002 when he retired. Mr. Poage’s responsibilities included supervising and managing both audit and tax professionals and providing services, primarily in the area of taxation, to private and publicly held companies engaged in the oil and natural gas industry. At February 1, 2008, Mr. Poage was Chairman of the Audit Committee of the Board of Directors.

     Directors hold office until the annual meeting of stockholders following their election or appointment and until their respective successors have been dully elected or appointed.

     Officers are appointed annually by the Board of Directors to serve at the Board’s discretion and until their respective successors in office are duly appointed.

     There are no family relationships between any of Parallel’s Directors or officers.

Consulting Arrangements

     As part of our overall business strategy, we continually monitor our general and administrative expenses. Decisions regarding our general and administrative expenses are made within parameters we believe to be compatible with our size, the level of our activities and projected future activities. Our goal is to keep general and administrative expenses at acceptable levels, without impairing the quality of services and organizational structure necessary for conducting our business. In this regard, we retain outside advisors and consultants from time to time to provide technical and administrative support services in the operation of our business.

Corporate Governance

     Under the Delaware General Corporation Law and Parallel’s bylaws, our business, property and affairs are managed by or under the direction of the Board of Directors. Members of the Board are kept informed of Parallel’s business through discussions with the Chairman of the Board, the Chief Executive Officer and other officers, by reviewing materials provided to them and by participating in meetings of the Board and its committees. We currently have five members of the Board, including Edward A. Nash, Larry C. Oldham, Martin B. Oring, Ray M. Poage and Jeffrey G. Shrader. The Board has determined that all of our Directors, other than Mr. Oldham, are “independent” for the purposes of NASD Rule 4200(a) (15). The Board based these determinations primarily on responses of the Directors and executive officers to questions regarding employment and compensation history, affiliations and family and other relationships and on discussions among the Directors.

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     The Board has four standing committees:

• the Audit Committee;

• the Corporate Governance and Nominating Committee;

• the Compensation Committee; and

• the Hedging and Acquisitions Committee.

Audit Committee

     The Audit Committee of the Board of Directors reviews the results of the annual audit of our Consolidated Financial Statements and recommendations of the independent auditors with respect to our accounting practices, policies and procedures. As prescribed by our Audit Committee charter, the Audit Committee also assists the Board of Directors in fulfilling its oversight responsibilities, reviewing our systems of internal accounting and financial controls, and the independent audit of our Consolidated Financial Statements.

     The Audit Committee of the Board of Directors consists of four Directors, all of whom have no financial or personal ties to Parallel (other than director compensation and equity ownership as described in this Annual Report on Form 10-K) and meet the Nasdaq standards for independence. The Board of Directors has determined that at least one member of the Audit Committee, Ray M. Poage, meets the criteria of an “audit committee financial expert” as that term is defined in Item 407(d)(5) of Regulation S-K, and is independent for purposes of Nasdaq listing standards and Rule 10A-3(b)(1) under the Securities Exchange Act of 1934, as amended. Mr. Poage’s background and experience includes service as a partner of KPMG LLP where Mr. Poage participated extensively in accounting, auditing and tax matters related to the oil and natural gas business. The Audit Committee operates under a charter which can be viewed in our website on www.plll.com.

     The current members of the Audit Committee are Edward A. Nash, Martin B. Oring, Ray M. Poage (Chairman) and Jeffrey G. Shrader.

Corporate Governance and Nominating Committee

     The Board’s Corporate Governance and Nominating Committee operates under a charter outlining the functions and responsibilities of the committee, including recommending to the full Board of Directors nominees for election as directors of Parallel, and making recommendations to the Board of Directors from time to time as to matters of corporate governance. The current members of this committee are Edward A. Nash, Martin B. Oring, Ray M. Poage and Jeffrey G. Shrader A copy of the charter can be viewed in our website at www.plll.com.

     The committee will consider candidates for Director suggested by stockholders. Stockholders wishing to suggest a candidate for Director should write to any one of the members of the committee at his address shown under Item 12 of this Annual Report on Form 10-K. Suggestions should include:

• a statement that the writer is a stockholder and is proposing a candidate for consideration by the committee;

• the name of and contact information for the candidate;

• a statement of the candidate’s age, business and educational experience;

• information sufficient to enable the committee to evaluate the candidate;

• a statement detailing any relationship between the candidate and any joint interest owners, customer, supplier or competitor of Parallel;

• detailed information about any relationship or understanding between the proposing stockholder and the candidate; and

• a statement that the candidate is willing to be considered and willing to serve as a Director if nominated and elected.

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Compensation Committee

     The current members of the Compensation Committee are Edward A. Nash, Martin B. Oring, Ray M. Poage and Jeffrey G. Shrader. Mr. Nash was appointed to serve on the committee on August 29, 2007 and presently acts as the Chairman of the Compensation Committee. The Compensation Committee of the Board of Directors administers and approves all elements of compensation and awards for our executive officers. The Committee has the responsibility to review and approve the corporate goals and objectives relevant to each executive officer’s compensation, evaluates individual performance of each executive in light of those goals and objectives, and determines and approves each executive’s compensation based on this evaluation.

     Members of the Committee are non-management directors who, in the opinion of the Board, satisfy the independence standards of the Nasdaq Global Market. The Committee has the sole authority to retain consultants and advisors as it may deem appropriate in its discretion, and sole authority to approve related fees and retention terms for these advisors.

     Generally, on its own initiative the Compensation Committee reviews the performance and compensation of all of our executives and then reviews and discusses its conclusions and recommendations with management.

Hedging and Acquisitions Committee

     The Hedging and Acquisitions Committee presently consists of all five of our Directors, including Messrs. Nash, Oldham, Oring, Poage and Shrader. Mr. Oring presently serves as Chairman of this committee. With respect to derivative contracts, the committee reviews, assists, and advises management on overall risk management strategies and techniques with a view to implementing prudent commodity and interest rate derivative arrangements. The Hedging and Acquisitions Committee also reviews with management plans and strategies for pursuing acquisitions.

Code of Ethics

     The Board has adopted a code of ethics which applies to all of our Directors, officers and employees, including our chief executive officer, chief financial officer and all other financial officers and executives. You may review the code of ethics on our website at www.plll.com. A copy of our code of ethics has also been filed with the Securities and Exchange Commission and is incorporated by reference as an exhibit to this Annual Report on Form 10-K. We will provide without charge to each person, upon written or oral request, a copy of our code of ethics. Requests should be directed to:

Manager of Investor Relations
Parallel Petroleum Corporation
1004 N. Big Spring, Suite 400
Midland, Texas 79701
Telephone: (432) 684-3727

Stockholder Communications with Directors

     Parallel stockholders who want to communicate with any individual Director can write to that Director at his address shown under Item 12 of this Annual Report on Form 10-K.

     Your letter should indicate that you are a Parallel stockholder. Depending on the subject matter, the Director will:

• if you request, forward the communication to the other Directors;

• request that management handle the inquiry directly, for example where it is a request for information about the company or it is a stock-related matter; or

• not forward the communication to the other Directors or management if it is primarily commercial in nature or if it relates to an improper or irrelevant topic.

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Director Attendance at Annual Meetings

     We typically schedule a Board meeting in conjunction with our annual meeting of stockholders and expect that our Directors will attend, absent a valid reason, such as illness or a schedule conflict. Last year, all of the individuals then serving as Directors attended our annual meeting of stockholders.

Section 16(a) Beneficial Ownership Reporting Compliance

     Section 16(a) of the Securities Exchange Act of 1934 requires our Directors and officers to file periodic reports with the Securities and Exchange Commission. These reports show the Directors’ and officers’ ownership, and the changes in ownership, of our common stock and other equity securities. To our knowledge, all Section 16(a) filing requirements were complied with during 2007.

ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

     Introduction and Overview

     The Compensation Committee of the Board of Directors is responsible for determining the types and amounts of compensation we pay to our executives. Our Committee operates under a written charter that you can view on our website at www.plll.com. The Board of Directors has affirmatively determined that each Director who is a member of the Committee meets the independence requirements of the Nasdaq Global Market. The Board determines, in its business judgment, whether a particular Director satisfies the requirements for membership on the Committee set forth in the Committee’s charter. None of the members of the Compensation Committee are current or former employees of Parallel or any of its subsidiaries.

     Our Compensation Committee is responsible for formulating and administering the overall compensation principles and plans for Parallel. This includes establishing the compensation paid to our officers, administering our compensation plans and, generally, reviewing our compensation programs at least annually.

     The Committee periodically meets in executive session without members of management or management directors present and reports to the Board of Directors on its actions and recommendations.

     We discuss below the philosophy, objectives and principles we followed last year for compensating our executive officers.

     Compensation Philosophy and Objectives

     The Committee’s compensation philosophy is to provide an executive compensation program that:

• is competitive with compensation programs offered by comparable companies engaged in businesses similar to ours;

• rewards performance, skills and talents necessary to advance our company objectives and further the interests of stockholders;

• is balanced between a fair and reasonable cash compensation and incentives linked to Parallel’s overall operating performance; and

• is fair to our executives, but within reasonable limits.

     The Company’s practice is and has been to link compensation with performance, measured at the company level, and to emphasize the importance of each executive’s contribution to the overall success of the Company. The overall objectives of our compensation philosophy are to:

• provide a reasonable and competitive level of current annual income;

• provide incentives that encourage our executives to continue their employment with us;

• motivate executives to accomplish our company goals and reward performance;

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• create an environment conducive to company-oriented success rather than individual success;

• align compensation and benefits with business strategy and competitive market data;

• encourage the application of prudent decision making processes in an industry marked by volatility and high risk; and

• provide for overall compensation arrangements that are fair and reasonable pay for achievements beneficial to Parallel and its stockholders.

     Our Committee supports these objectives by emphasizing compensation arrangements that we believe will attract and retain qualified executives and reward them for creating a solid platform for the long-term growth and success of Parallel. At the same time, we are mindful of, and try to balance our executive compensation arrangements with, the interests and concerns of stockholders.

     To more fully understand our current compensation philosophies and practices, it is important to keep in mind some historical milestones that have influenced the shaping of our compensation practices. For instance, it was not until May 2002 that we had more than seven employees, as compared to 43 employees that we currently have; our total market capitalization (including shares held by our officers and directors) at December 31, 2002 was approximately $58.0 million, as compared to a total market capitalization (including shares held by our officers and directors) of approximately $727.0 million at December 31, 2007; and it was not until the latter part of 2004 that the market price of our stock consistently exceeded $5.00 per share. Given our small size, limited staff and limited resources in earlier years, the compensation of our executives consisted primarily of salaries, cash bonuses and stock options, with an emphasis on the use of stock options. Since November 2002, however, we have limited the use of stock option awards to our executives and we relied more heavily on our Incentive and Retention Plan as a long-term incentive. For 2007, we chose, as we have in the past, to continue a relatively simple compensation framework for our executives. We believe the benefits of this approach include maintaining a higher degree of understanding and certainty for our executives as well as the investing public, and avoiding complex benefit packages and agreements that are less transparent than our compensation program and that require significant time and cost to properly administer. However, as we describe below under “Analysis and Outlook”, we anticipate adopting a long-term equity based incentive plan, in part due to the oil and natural gas exploration and production industry continuing to experience increased competition for qualified personnel at all levels.

     Compensation Components

     Our judgments regarding executive compensation are primarily based upon our assessment of company performance, and each executive officer’s leadership, performance and individual contributions to Parallel’s business. The accounting and tax treatment of different elements of compensation has not had a significant impact on our use of any particular form of compensation. In reviewing the overall compensation of our officers, we have historically considered and used a mix of the following components or elements of executive compensation:

• base salaries;

• stock option grants;

• annual cash bonuses;

• health and life insurance plans which are generally available to all of our employees;

• contributions by Parallel to our 401(k) retirement plan;

• an equity based cash incentive plan;

• change of control arrangements; and

• limited perquisites and personal benefits provided by Parallel to our executive officers.

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     To help give you a better understanding of the overall compensation picture of our executives, we have included the following table showing the elements of executive compensation we have used in the past and certain types of executive compensation that we have not used:

	Used by
	Parallel		Used by		Not Used by
Elements of Compensation	Prior to 2007		Parallel in 2007		Parallel
Base salaries		ü		ü
Employment agreements						ü
Cash bonuses		ü		ü
Stock awards						ü
Change of control/severence arrangements		ü		ü
Defined benefit pension plan						ü
Defined contribution plan		ü		ü
Stock options		ü
Tax gross-ups		ü
Employee stock purchase/ ownership plan						ü
Supplemental executive retirement plans/benefits						ü
Deferred compensation plan						ü
Incentive and retention plan		ü		ü
Limited perquisites and personal benefits		ü		ü

     Evaluation Factors

     In addition to comparing the compensation packages of our officers with the compensation packages of officers of other companies similar to Parallel, we also relied, as we have in the past, on our general knowledge and experience in the oil and natural gas industry, focusing on a subjective analysis of each of our executive’s contributions to Parallel’s overall performance. Except for comparing the salaries and bonuses of our executives with the salaries and bonuses of executives in our peer group of companies, other specific performance levels or “benchmarks” were not used in 2007 to establish salaries, cash bonuses or grant stock options. We do take into account historic comparisons of Parallel’s financial and operational performance. The link between pay and company performance is based primarily on the Compensation Committee’s evaluation of periodic results of certain elements of company performance. Generally, our evaluations are influenced equally by operational metrics and financial metrics.

     We have not adopted specific target or performance levels with respect to quantitative or qualitative performance-related factors which would automatically result in increases or decreases in compensation. Instead, we make subjective determinations based upon a consideration of many factors, including those we have described below. We have not assigned relative weights or rankings to these factors. Specific elements of company performance and individual performance that we consider in setting compensation policies and making compensation decisions include the following factors, several of which we consider in the context of Parallel alone and by comparison with peer companies:

• growth in the quantity and value of our proved oil and natural gas reserves;

• volumes of oil and natural gas produced by Parallel and our executives’ ability to replace oil and natural gas produced with new oil and natural gas reserves;

• cash flows from operations;

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• revenues;

• earnings per share;

• the market value of our common stock;

• the extent to which the officers have been successful in finding and creating opportunities for Parallel to participate in acquisition, exploitation and drilling ventures having quality prospects;

• the ability of our officers to formulate and maintain sound budgets for our business activities;

• the overall financial condition of Parallel;

• the achievement by management of specific tasks and goals set by the Board of Directors from time to time;

• the effectiveness of our compensation packages in motivating officers to remain in Parallel’s employment;

• oil and gas finding costs and operating costs; and

• the ability of our executives to effectively implement risk management practices, including oil and natural gas and interest rate hedging activities.

     In addition to considering the elements of performance described above, other factors that we consider in determining compensation include:

• longevity of service; and

• the individual performance, leadership, business knowledge and level of responsibility of our officers.

     Although we believe the key components of our executive compensation program, base salary, cash bonuses and the potential for awards under our Incentive and Retention Plan, have provided an adequate mix of different types of compensation that reflect the outcome of our analysis of the evaluation factors described above, after further review and evaluation of the adequacy and effectiveness of our long-term incentive compensation arrangements we also believe that the implementation of a long-term incentive plan could provide a platform for more definitive long-term incentives for our executives while at the same time creating a more performance based award program. For instance, while we believe that potential payments under our Incentive and Retention Plan are reflective of longer-term operational metrics such as reserve growth, increased production and increased cash flows from operations, the plan (a) does not contain provision for any compensation payments for Company or individual performance, whether short-term or long-term, (b) does not provide for any payments unless and until a triggering event occurs, and (c) does not provide certainty of awards for any individual since awards will not be made until a triggering event does occur. More information about the Incentive and Retention Plan and the implementation of a long-term incentive plan is set forth below under the caption “Incentive and Retention Plan” and “Analysis and Outlook”. Base salaries and cash bonuses are more closely linked to the short-term objectives of providing reasonable and competitive levels of current annual increases. Since the elements of compensation we use are fairly limited, the results of our evaluation of the Company’s performance and each executive’s individual performance are reflected more by the amounts of compensation we award, rather than by type of award.

     With our compensation philosophy and objectives in mind, we discuss below in more detail the key elements of executive compensation and the factors underlying our decisions for 2007.

     Base Salaries

     Salary levels are based on factors including individual and company performance, level and scope of responsibility and competitive salary levels within the industry. We do not give specific weights to these factors. The Committee determines base salary levels by reviewing comparative salary data gathered by our CEO and CFO and

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by the Committee’s consultant, and by reviewing publicly available information such as proxy statements filed by other exploration and production companies with similar market capitalizations. As the beginning point for determining base salaries, we reviewed an initial list of 57 publicly-traded companies in our industry. This initial list was then narrowed to 18 companies following our review and after making certain changes to the proposed peer group that had been suggested by management. This peer group was selected based primarily on the similarity of total revenues and business models of Parallel and the companies in the peer group. Using this peer group, we targeted the median percentile range of salaries and cash bonuses for executive officers of the eighteen company peer group. The peer group consisted of the following:

Abraxas Petroleum Corporation
Arena Resources, Inc.
Bill Barrett Corporation
Carrizo Oil & Gas, Inc.
Concho Resources, Inc.
Delta Petroleum Corporation
Edge Petroleum Corporation
GMX Resources, Inc.
Goodrich Petroleum Corporation

Gulfport Energy Corporation
Legacy Reserves, LP
Petroleum Development Corporation
PetroQuest Energy, Inc.
Rex Energy Corporation
Rosetta Resources, Inc.
The Exploration Company of Delaware, Inc.
Venoco, Inc.
Warren Resources, Inc.

     Base salaries for each executive are reviewed individually on an annual basis. Salary adjustments are based on the individual’s experience, background and responsibilities, the individual’s performance during the prior year, the general movement of salaries in the marketplace, and our financial position. As a result of these factors, an executive’s base salary may be above or below the base salaries of executives in other oil and gas exploration and production companies at any point in time. Upon completion of the Committee’s review and evaluation, and based on the financial and operations results and the criteria for the salary determinations, our named executive officers received the following increases in their annual base salaries:

Mr. Oldham	—	from	$	330,000	to	$	350,000
Mr. Tiffin	—	from	$	275,000	to	$	300,000
Mr. Rutherford	—	from	$	175,000	to	$	190,000
Mr. Foster	—	from	$	190,000	to	$	210,000
Mr. Bayley	—	from	$	175,000	to	$	190,000

     Cash Bonuses

     Historically, we have used, and continue to use, short-term incentives in the form of annual cash bonuses to compensate executive officers. Annual cash bonuses are viewed by the Committee as supplemental short-term incentives in recognition of Parallel’s overall performance and the efforts made by our executives during a particular year. Cash bonuses are based on a subjective determination of amounts we deem sufficient to reward our executives and remain competitive within our geographic environment. As with base salaries, we also targeted the median percentile rankings of our eighteen-company peer group. We did not use specific performance targets when determining cash bonuses. The Committee considers Parallel’s overall performance, the individual performance of each executive, and the level of responsibility and experience of each executive to determine the final bonus amounts. Bonuses are paid at the discretion of the Committee based on the overall accomplishments of Parallel and individual performance.

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     After completing our review in December 2007, the Committee awarded cash bonuses as follows:

	Amount of
	Bonus
Mr. Oldham	$	200,000
Mr. Tiffin	$	175,000
Mr. Rutherford	$	70,000
Mr. Foster	$	70,000
Mr. Bayley	$	70,000

     There were no material differences in the decision making process we used in determining the salaries and cash bonuses of our respective officers.

     Stock Options

     Prior to 2003, we relied heavily on the use of stock options as a form of compensation because of our size and limited cash resources. The Committee did not make any option grants to any officers during the period from 2003 to 2007, and the last time we granted stock options to our Chief Executive Officer, Mr. Oldham, was on June 20, 2001 when he was granted a stock option to purchase 200,000 shares of common stock at an exercise price of $4.97 per share, the fair market value of the common stock on the date of grant. In May 2003, Mr. Oldham voluntarily relinquished 100,000 shares of common stock underlying this option in order to restore and make available shares of stock for option grants to non-officer employees. The last time we granted stock options to any of our other executives was on November 14, 2002 when we granted stock options to Mr. Tiffin, our Chief Operating Officer, and to Mr. Foster, our Chief Financial Officer. Mr. Tiffin was granted a stock option to purchase 50,000 shares of common stock and Mr. Foster was granted a stock option to purchase 35,000 shares of stock. The exercise price of both stock options was $2.18 per share, the fair market value of the common stock on the date of grant.

     We do not have a specific program or plan with regard to the timing or dating of option grants. Our stock options have not been granted at regular intervals or on pre-determined dates. The Committee’s practice as to when options are granted has historically been made at the discretion of the Committee. Generally, no distinctions have been made in the timing of option grants to executives as compared to employees. Since October 1993, stock options have been granted to our officers and employees on thirteen different occasions. On eight occasions, options were awarded to employees only; on four occasions options were awarded to officers and employees; and on one occasion an option was awarded to one officer.

     We do not grant discounted options and exercise prices are not based on a formula. All of our options are granted “at-the-money.” In other words, the exercise price of the option equals the fair market value of the underlying stock on the actual date of grant. As part of our 2006 compensation review, we conducted an internal review of all of our stock option grants going back to August 1996 and did not find any instances of option “backdating”, nor did we backdate any options in 2007. In addition, we have not “repriced” any of our stock options and do not intend to do so.

     Historically, the granting of options has not been purposefully timed around the public announcement of material non-public information. Our Committee’s practice has been to meet whenever one or more of the Committee members expresses a desire to discuss in executive session any particular aspect of executive compensation, and the proximity of any stock option grant to earnings or other material announcements is coincidental. We have not and do not plan to purposefully time the release of material non-public information for the purpose of affecting the value of executive compensation.

     Other Compensation

     Our executive officers participate in a 401(k) retirement and savings plan on the same basis as other employees. Parallel “matches” certain employee contributions to its 401(k) retirement plan with cash contributions. Company matching amounts for the named executive officers are included under the caption “All Other Compensation” in the Summary Compensation Table on page 73.

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     We do not have a written policy or formula regarding the adjustment, reduction or recovery of awards of payments if company performance is not optimal. However, the Committee does take into account compensation realized or potentially realizable from prior compensation awards in setting new types and amounts of compensation. Although we have never decreased the compensation of any of our executive officers, the percentage increases in annual salaries and cash bonuses vary from year to year, with some increases being smaller than previous years.

     Allocation of Amounts and Types of Compensation

     Other than our 401(k) retirement plan and outstanding stock options that were granted to our executive officers prior to 2003, and although we believe that our Incentive and Retention Plan does have some long-term incentive characteristics, we do not presently have in place what we would consider to be a traditional type of long-term incentive program. Since we have not had a traditional form of long-term incentive program, the method of allocating different forms of long-term compensation has not been a significant consideration for us. The Committee has not adopted a specific policy for allocating between long-term and currently paid out compensation, nor have we adopted a specific policy for allocating between cash and non-cash compensation. However, since December 2002, the compensation we have paid to our executives has emphasized the use of cash rather than non-cash compensation. We have chosen to do this in order to maintain and continue our practice of having a simplified, but effective and competitive, compensation package. In determining the amount and mix of compensation elements for each executive officer, the Committee relies on judgment, not upon fixed guidelines or formulas, or short term changes in our stock price. Specific allocation policies have not been applied by the Committee largely because company performance in the oil and natural gas industry is often volatile and cyclical and Parallel’s performance in any given year, whether favorable or unfavorable, may not necessarily be representative of immediate past results or future performance. The Committee also recognizes that company performance is often the result of factors beyond the control of Parallel or its executives, especially oil and natural gas prices. For instance, even when we believe our executives have demonstrated superior individual performance during any particular year, the year-end value and quantities of our proved reserves, which are based on oil and gas prices at December 31 of each year, may reflect a level of company performance, whether good or bad, that is not necessarily reflective of actual company and individual performance. Consequently, the Compensation Committee examines and recommends executive compensation levels based on the evaluation factors described above compared over a period of time, rather than applying these factors on an isolated or “snapshot” basis at the time compensation levels are established by the Committee. In this regard, and partly due to the peculiarities of financial accounting requirements for exploration and production companies, the Committee emphasizes a subjective approach to allocating the amounts and types of compensation for our executives.

     By choosing to pay the elements of compensation discussed above, we try to maintain a simple and competitive position for our total compensation package.

     Internal and External Assistance

     Our Committee has the authority to retain, at Parallel’s expense, compensation consultants. Utilizing this authority, our Committee engaged the services of an independent compensation consultant, Mercer Human Resources Consultants, Inc., to assist us in our review of executive compensation for 2007. The consultant reports directly to the Committee. We specifically instructed our consultant to use its data base to prepare a peer group of companies based on similarity of revenues and business models and to provide the Committee with information regarding this peer group with respect to base salaries, bonuses, long-term incentives and other types of compensation, as well overall current compensation trends and practices. In the course of our evaluation of executive compensation last year, we compared the data provided to us by our consultant to components and levels of compensation paid to our executives. We also compared the companies suggested by our consultant and by management for inclusion in the peer group. This year, our use of data provided by management was much more limited. Although management provided the Committee with a proposed peer group, we selected the peer group suggested by Mercer, after taking into account changes suggested by management. Our final selection was based primarily on the similarity of revenue and business models of Parallel and the peer companies. Our review included comparisons of pay data for comparable executive positions and compensation components used by the peer group. Our independent consultant also provided the Committee with statistical information and advice on current competitive compensation practices and trends in the marketplace.

     When our Committee meets in formal session, we do so outside the presence of management, including Mr. Oldham, our Chief Executive Officer. However, the Compensation Committee did seek informal input and insight of Mr. Oldham and Mr. Tiffin concerning broad, general topics such as the overall design and levels of our

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existing compensation program, the morale of our executive officers, and any specific factors that they believed to be appropriate for the Committee’s consideration and which the Committee may not be aware of, such as individual performance, and extraordinary day-to-day efforts or accomplishments of any of our executives.

     Change of Control Arrangements

     Our stock option plans and our Incentive and Retention Plan contain “change of control” provisions. We use these provisions in an effort to provide some assurance to the Board of Directors that the Board will be able to rely upon our executives continuing in their positions with Parallel, and that Parallel will be able to rely upon each executive’s services and advice as to the best interests of Parallel and its stockholders without concern that the executive might be distracted by the personal uncertainties and risks created by any proposed or threatened change of control. More information about these change of control provisions can be found under the caption “Potential Payments Upon Change of Control” on page 77.

     Stock Option Plans

     As described in more detail under the caption “Potential Payments Upon Change of Control” on page 77, the Compensation Committee may adjust the stock options currently outstanding and held by our executives upon the occurrence of a change of control. With this authority, the Compensation Committee may in its discretion elect to accelerate the vesting of any stock options that were not fully vested at the time of a change of control. In addition, under some of our stock option plans, acceleration of vesting schedules will automatically occur. In the “Outstanding Equity Awards at Fiscal Year-End” table on page 76, you can see the stock options currently held by our executives and the exercise prices for each of these options. Mr. Oldham, our Chief Executive Officer, is the only executive officer that has a stock option that had not fully vested as of December 31, 2007. As described in that table, Mr. Oldham holds a stock option to purchase a total of 37,500 shares of common stock which remained unvested to the extent of 30,000 shares at December 31, 2007. If a change of control had occurred on December 31, 2007, a total of 30,000 shares would have automatically vested on that date. Under the terms of Mr. Oldham’s stock option, he would have to pay an aggregate of $186,375 to purchase all 37,500 shares. The value of the portion of the option subject to accelerated vesting would have been $379,800 ($17.63 per share closing price on December 31, 2007, multiplied by 30,000 shares subject to accelerated vesting minus $149,100, the aggregate exercise price for the unvested portion of the option).

     Incentive and Retention Plan

     In 2002 and before, long-term incentives were made up of stock options. In 2004, upon recommendation of the Committee, we adopted the Incentive and Retention Plan described in more detail on page 78. Generally, this plan authorizes the Committee to grant executive officers awards in the form of “base shares,” with one base share being equated to one share of our common stock. The value of base shares fluctuates directly with changes in the price of Parallel’s stock which we believe more closely ties the interests of our executives directly to those of stockholders. The base shares are paid out only upon a “corporate transaction” or a “change of control”. These triggering events are further described below and on page 77. Payouts, when triggered, are to be paid in cash. The Committee will determine the total number of base shares to grant each executive officer by using individual performance, level of responsibility, experience and the extent to which each executive officer may have contributed to the occurrence of a triggering event under the plan, as well as the outcome of the event. All of our other employees and consultants are also eligible to participate in this plan.

     The Incentive and Retention Plan was designed to align the interests of executives with stockholders and to provide each executive with a significant incentive to manage the Company from the perspective of an owner with an equity stake in the business. When we were in the initial stages of formulating this plan, we began with the concept of a more traditional long-term incentive plan which would provide our executives with potential cash awards based on year-to-year comparisons of the growth in our proved oil and gas reserves or related exploration and production criteria, with these annual cash awards being predicated on various performance factors, such as a predetermined percentage increase in our proved oil and natural gas reserves or other related criteria. However, we realized that under this approach annual cash payments could result simply as a result of increases in the prices of oil and natural gas which would not necessarily equate to actual growth in our reserves or any specific achievements by our executives and under circumstances that might not result in additional value to our stockholders. After further consideration, we decided to tie any potential rewards under this plan to the market price of our stock. Although not linked to any specific performance measures, the Committee believed that linking potential rewards to the market

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price of our stock would reflect a “bundling” of company performance measures that are of importance to investors in smaller exploration and production companies like Parallel, and which would be reflected in the market price of our stock. In addition, and instead of providing for “automatic” annual bonuses, we believed it important to reward our executives under circumstances that were more likely to coincide with events that could also result in our stockholders realizing value. Thus, one prong of the Incentive and Retention Plan provides for payments only when there is a “corporate transaction,” such as a merger or sale of Parallel. The second prong of the plan provides for payments upon the occurrence of a change on control. We structured the Incentive and Retention Plan in this fashion primarily to satisfy our objective of retaining management, and to more closely connect potential payments to our executives to an event in which all of our stockholders would be more likely to realize value from their investments in Parallel. Further, the Committee remains of the belief that the Incentive and Retention Plan should eliminate, or at least reduce, any reluctance management might have to pursue potential corporate transactions that may be in the best interests of stockholders. The cash benefits are payable in one lump-sum.

     The oil and natural gas industry in our specific areas of operation continues to experience increases in leasing, acquisitions, drilling and development activities. This activity has resulted in significant management turnover within the areas we operate, largely because of greater compensation packages and incentives being offered by our competitors. At the time we implemented the plan, the Committee believed that the potential rewards to our executives under the Incentive and Retention Plan would provide the necessary incentive for our executives to remain employed by, and diligently pursue the goals of, Parallel. Since adopting the plan, none of our officers have left our employment. However, recognizing that the plan has not resulted in any compensation to our executives over the last four years, the Committee is presently re-evaluating this area of our compensation program.

     Under the Incentive and Retention Plan, our officers, employees and consultants are eligible to receive a one-time performance payment upon the occurrence of a corporate transaction or a one-time retention payment upon the occurrence of a change of control. Generally, a corporate transaction means an acquisition of Parallel, a sale of substantially all of Parallel’s assets or the dissolution of Parallel. A change of control generally means the acquisition of 60% or more of our outstanding common stock or an event that results in our current Directors ceasing to constitute a majority of the Board of Directors.

     In the case of a corporate transaction, the total aggregate potential payments would be equal to the sum of (a) the per share price received by all stockholders minus a base price of $3.73 per share, multiplied by 1,080,362 “base shares,” plus (b) the per share price received by all stockholders minus an “additional base price” of $8.62 per share, multiplied by 400,000 “additional base shares”. If a change of control occurs, the aggregate potential payments to all plan participants would be equal to the sum of (a) the per share closing price of Parallel’s common stock on the day immediately preceding the change of control, minus the base price of $3.73 per share, multiplied by 1,080,362, plus (b) the per share closing price of Parallel’s common stock on the day immediately preceding the change of control, minus an “additional base price” of $8.62 per share, multiplied by 400,000 “additional base shares.”

     If a corporate transaction or change of control occurs, the Compensation Committee has the discretion to allocate for payment to each of our executives, employees or consultants a portion of the total performance bonus or retention payment as the Committee determines in its sole discretion. Although the Committee has not made any awards under our Incentive and Retention Plan, for illustration purposes, assuming a corporate transaction or change of control occurred on December 31, 2007, and that the applicable price of our common stock was $17.63 per share, the closing price of our common stock as of December 31, 2007, the total aggregate potential payments to all eligible participants would have been approximately $18.6 million.

     The change of control provisions in our stock option plans and in the Incentive and Retention Plan utilize “single triggers.” As compared to “double triggers,” we believe that single triggers provide a more definitive outcome for our executives if a triggering event does occur and are more likely to prevent an executive from becoming entangled in various interpretive issues concerning the applicability of a second or double trigger to any particular triggering event. For these reasons, coupled with the fact that none of our executives have deferred compensation arrangements or employment or other post-termination compensation agreements with Parallel, we believe the use of single triggers is not inconsistent with the best interests of Parallel or our stockholders.

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     Stock Ownership/Retention Guidelines

     We do not have formal written guidelines or policy statements requiring specified levels of stock ownership or “holding” practices. Under our policy covering insider trading procedures, our executives, their spouses and other immediate family members sharing the executive’s household are prohibited from selling any securities of Parallel that are not owned at the time of the sale, a “short sale.” Also, no such person may buy or sell puts, calls or exchange-traded options in Parallel’s securities. These transactions are speculative in nature and may involve a “bet against the company” which we believe is inappropriate for our insiders.

     Perquisites and Personal Benefits

     We have provided limited perquisites and personal benefits to our executives, including club memberships and allowing our executives a choice of receiving a car allowance or personal use of a company provided vehicle. We encourage our executives to belong to a social club so that they have an appropriate entertainment forum for customers and appropriate interaction with their communities.

     Our executives also participate in Parallel’s other benefit plans on the same terms as other employees. These plans include medical and dental insurance, and life insurance. All employees, including our executives, age fifty or over are also eligible to participate in an extended health care coverage plan that we maintain. We do not have charitable gift matching or discounts on products.

     The types and amounts of perquisites we provide to our executives are included in the “All Other Compensation” column of the Summary Compensation Table on page 73.

     Analysis and Outlook

     During our review of 2007 compensation, we determined that the compensation paid to our executives was below that of the peer group selected by the Committee. The actions of the Compensation Committee in increasing our executives’ salaries and awarding cash bonuses were based mostly on the Committee’s decision to bring our executives’ salaries and bonuses up to the median percentile range of the salaries and bonuses of executives of our peer companies. In addition to performance at the Company level, the Committee also compared the individual efforts, talents and performance of Parallel’s executives with the individuals performing similar functions for the peer companies, some of whom are known by one or more members of the Committee. The Committee’s decisions were also influenced by the individual efforts of each of our executives in response to specific requests made by our Board of Directors. Going forward, the Committee intends to use, more so than it has in the past, objective performance criteria to support certain components of executive compensation rather than the more subjective approach that we have historically used. Based on discussions the Committee has had with our consultant, management and our own deliberations, the Committee further determined that the Incentive and Retention Plan may not be providing the types of incentives anticipated when the plan was originally implemented. In particular, the Committee believes the Incentive and Retention Plan may not continue to provide the necessary incentives to attract and retain qualified oil and gas industry personnel at a time of increased competition for such personnel at all levels and that the absence of an equity based long-term incentive plan could make it more difficult to recruit and retain qualified personnel. Towards this end, and subject to applicable regulatory and stockholder approval requirements, the Committee intends to adopt a long-term incentive plan that would authorize awards of stock options, restricted stock, performance awards or other equity based awards, although no such plan had been adopted by the Compensation Committee at the time our Annual Report on Form 10-K, which includes this Compensation Discussion and Analysis, was filed with the SEC.

     Limit on Deductibility of Certain Compensation

     Provisions of the Internal Revenue Code that restrict the deductibility of certain compensation over one million dollars per year were not a factor in our considerations or recommendations for our 2007 compensation review. Section 162(m) of the Code currently imposes a $1 million limitation on the deductibility of certain compensation paid to our executives. Excluded from the limitation is compensation that is “performance based.” For compensation to be performance based, it must meet certain criteria, including being based on predetermined objective standards approved by stockholders. Compensation to our executives does not currently qualify as “performance based compensation” and thus is not deductible by us for federal income tax purposes.

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Compensation Committee Report

     The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis with management.

     Based on its review and discussions, the Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in our Annual Report on Form 10-K for the year ended December 31, 2007 and in our Proxy Statement for this year’s Annual Meeting of Stockholders.

Members of the Compensation Committee

Edward A. Nash (Chairman)
Martin B. Oring
Ray M. Poage
Jeffrey G. Shrader

Summary of Annual Compensation

     The table below shows a summary of the types and amounts of compensation paid for 2006 and 2007 to Larry C. Oldham, our President and Chief Executive Officer, and to our other four executive officers for the years ended December 31, 2007 and 2006. Also included is the compensation we paid to Thomas R. Cambridge, our former Chairman of the Board of Directors, for the same years. Mr. Cambridge retired from the Board of Directors on June 26, 2007.

Summary Compensation Table

														Change in
														Pension Value
														and
												Non-Equity		Nonqualified		All
												Incentive		Deferred		Other
Name and							Stock		Option			Plan Com-		Compensation		Com-
Principal Position	Year		Salary		Bonus		Awards		Awards			pensation		Earnings		pensation(1)			Total
L. C. Oldham		2007	$	330,000	$	200,000		0		12,303	(2)		0		0	$	59,415	(3)	$	601,718
President, Chief Executive Officer and Director		2006	$	300,000	$	185,000		0		16,683	(2)		0		0	$	51,090	(3)	$	552,773
D. E. Tiffin		2007	$	275,000	$	175,000		0		0			0		0	$	47,730	(4)	$	497,730
Chief Operating Officer		2006	$	250,000	$	147,500		0		0			0		0	$	43,247	(4)	$	440,747
E. A. Bayley		2007	$	175,000	$	70,000		0		0			0		0	$	41,640	(5)	$	286,640
Vice President of Corporate Engineering		2006	$	160,000	$	60,000		0		0			0		0	$	39,321	(5)	$	259,321
J. S. Rutherford		2007	$	175,000	$	70,000		0		0			0		0	$	39,560	(6)	$	284,560
Vice President of Land and Administration		2006	$	160,000	$	60,000		0		0			0		0	$	38,174	(6)	$	258,174
S. D. Foster		2007	$	190,000	$	70,000		0		0			0		0	$	44,493	(7)	$	304,493
Chief Financial Officer		2006	$	175,000	$	60,000		0		0			0		0	$	45,547	(7)	$	280,547
T. R. Cambridge(8)		2007	$	70,889		0		0		0			0		0		0		$	70,889
Former Chairman of the Board of Directors		2006	$	135,000	$	60,000		0		0			0		0	$	5,152		$	200,152

(1) Included in this column is (a) all other compensation received by the named executive officer but not reported under any other column of this table, and (b) the incremental cost of all perquisites and personal benefits for each named executive officer, in each case as identified in the following table:

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		Mr.		Mr.		Mr.		Mr.		Mr.		Mr.
		Oldham		Tiffin		Rutherford		Foster		Bayley		Cambridge
Personal use of club memberships(a)	2007	$	0	$	0	$	1,547	$	1,670	$	2,085	$	0
	2006	$	0	$	0	$	3,376	$	3,652	$	0	$	0
Personal use of comp any car(b)	2007	$	4,625	$	0	$	5,644	$	0	$	10,291	$	0
	2006	$	1,723	$	0	$	1,179	$	0	$	8,401	$	0
Car allowance	2007	$	0	$	8,050	$	0	$	8,050	$	0	$	0
	2006	$	0	$	6,000	$	0	$	6,000	$	0	$	0
Personal use of office space(c)	2007	$	1,809	$	0	$	0	$	0	$	0	$	0
	2006	$	2,366	$	0	$	0	$	0	$	0	$	0
CEO life insurance(d)	2007	$	4,063	$	0	$	0	$	0	$	0	$	0
	2006	$	3,793	$	0	$	0	$	0	$	0	$	0
Personal use of charter aircraft	2007		(e)	$	0		(e)	$	0	$	0	$	0
	2006		(e)		(e)		(e)	$	0	$	0	$	0
Tax “gross up”(f)	2007	$	0	$	0	$	0	$	0	$	0	$	0
	2006	$	3,629	$	1,687	$	3,697	$	3,559	$	3,836	$	5,152
Other(g)	2007	$	5,935	$	0	$	0	$	0	$	0	$	0

(a)	The value of personal use of club memberships represents that portion of annual club dues determined by multiplying the total annual club dues by a fraction equal to expenses for personal use divided by total business and personal expenses. All employees pay or reimburse us for their personal expenses.
(b)	Personal use of a company car is based on the sum of the fair lease value of the car, maintenance expense and gas expense, multiplied by a fraction, the numerator of which is the number of miles driven for personal use and the denominator of which is the total number of miles driven.
(c)	Includes personal use of office space by Mr. Oldham’s wife for charitable, civic and personal activities. The value has been determined by multiplying the number of square feet in the office by the cost per square foot paid by Parallel under its lease agreement covering its executive offices, and as adjusted for a proportionate share of common area maintenance expenses.
(d)	We provide a $100,000 whole life insurance policy for Mr. Oldham and pay the premiums for maintaining the policy in force.
(e)	From time to time, the executive’s spouse will accompany the executive on business trips when there is an unoccupied seat on the aircraft. However, there is no aggregate incremental cost to us.
(f)	The tax “gross up” payments for each named executive officer were made in connection with cash bonuses in the amount of $10,000 that were awarded to each named executive officer on December 6, 2006.
(g)	Includes the cost of commercial airfare for Mr. Oldham’s wife when she accompanied him on seven separate business trips.

(2)

The amounts shown in this column represent the dollar amount we recognized for financial statement reporting purposes, computed in accordance with FAS 123(R), of an option award made to Mr. Oldham prior to 2006. For a discussion of valuation assumptions, see Note 11 to our Consolidated Financial Statements included in this Annual Report on Form 10-K.

(3)

For 2007, such amount includes Parallel’s contribution in the amount of $19,800 to Mr. Oldham’s individual retirement account maintained under Parallel’s 401(k) plan; insurance premiums in the amount of $23,183 for nondiscriminatory group life, medical, disability, long-term care and dental insurance; and $16,432 representing the total value of all other compensation and perquisites and personal benefits provided to Mr. Oldham as described in

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footnote 1. For 2006, such amount includes Parallel’s 2006 contribution in the amount of $18,000 to Mr. Oldham’s individual retirement account maintained under Parallel’s 401(k) plan; insurance premiums in the amount of $21,579 for nondiscriminatory group life, medical, disability, long-term care and dental insurance; and $11,511 representing the total value of all other compensation and perquisites and personal benefits provided to Mr. Oldham as described in footnote 1.

(4) For 2007, such amount includes Parallel’s contribution in the amount of $16,500 to Mr. Tiffin’s individual retirement account maintained under Parallel’s 401(k) plan; insurance premiums in the amount of $23,180 for nondiscriminatory group life, medical, disability, long-term care and dental insurance; and $8,050 representing the total value of all other compensation and perquisites and personal benefits provided to Mr. Tiffin as described in footnote 1. For 2006, such amount includes Parallel’s 2006 contribution in the amount of $15,000 to Mr. Tiffin’s individual retirement account maintained under Parallel’s 401(k) plan; insurance premiums in the amount of $20,560 for nondiscriminatory group life, medical, disability, long-term care and dental insurance; and $7,687 representing the total value of all other compensation and perquisites and personal benefits provided to Mr. Tiffin as described in footnote 1.

(5) For 2007, such amount includes Parallel’s contribution in the amount of $10,500 to Mr. Bayley’s individual retirement account maintained under Parallel’s 401(k) plan; insurance premiums in the amount of $18,764 for nondiscriminatory group life, medical, disability, long-term care and dental insurance; and $12,376 representing the total value of all other compensation and perquisites and personal benefits provided to Mr. Bayley as described in footnote 1. For 2006, such amount includes Parallel’s 2006 contribution in the amount of $9,600 to Mr. Bayley’s individual retirement account maintained under Parallel’s 401(k) plan; insurance premiums in the amount of $17,484 for nondiscriminatory group life, medical, disability, long-term care and dental insurance; and $12,237 representing the total value of all other compensation and perquisites and personal benefits provided to Mr. Bayley as described in footnote 1.

(6) For 2007, such amount includes Parallel’s contribution in the amount of $10,500 to Mr. Rutherford’s individual retirement account maintained under the 401(k) plan; insurance premiums in the amount of $21,869 for nondiscriminatory group life, medical, disability and dental insurance; and $7,191 representing the total value of all other compensation and perquisites and personal benefits provided to Mr. Rutherford as described in footnote 1. For 2006, such amount includes Parallel’s 2006 contribution in the amount of $9,600 to Mr. Rutherford’s individual retirement account maintained under the 401(k) plan; insurance premiums in the amount of $20,322 for nondiscriminatory group life, medical, disability and dental insurance; and $8,252 representing the total value of all other compensation and perquisites and personal benefits provided to Mr. Rutherford as described in footnote 1.

(7) For 2007, such amount includes Parallel’s contribution in the amount of $11,400 to Mr. Foster’s individual retirement account maintained under Parallel’s 401(k) plan; insurance premiums in the amount of $23,373 for nondiscriminatory group life, medical, disability, long-term care and dental insurance; and $9,720 representing the total value of all other compensation and perquisites and personal benefits provided to Mr. Foster as described in footnote 1. For 2006, such amount includes Parallel’s 2006 contribution in the amount of $10,500 to Mr. Foster’s individual retirement account maintained under Parallel’s 401(k) plan; insurance premiums in the amount of $21,836 for nondiscriminatory group life, medical, disability, long-term care and dental insurance; and $13,211 representing the total value of all other compensation and perquisites and personal benefits provided to Mr. Foster as described in footnote 1.

(8) The 2007 information shown in this table for Mr. Cambridge is for the period from January 1, 2007 to June 26, 2007, the date of his retirement. Except as described under “Item 13. Certain Relationships and Related Transactions, and Director Independence” on page 90, no other payments were made to Mr. Cambridge or his affiliated entities for the fiscal year ended December 31, 2007.

Outstanding Equity Awards at Fiscal Year-End

     Historically, we have used stock options as part of the overall compensation of Directors, officers and employees. However, we did not grant any stock options in 2007 to any of the executive officers named in the Summary Compensation Table. Summary descriptions of our stock option plans are included in this Annual Report on Form 10-K, beginning on page 84 so you can review the types of options we have granted in the past and the significant features of our stock options.

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          In the table below, we show certain information about the outstanding equity awards held by the named executive officers at December 31, 2007.

Outstanding Equity Awards at 2007 Fiscal Year-End

	Option Awards												Stock Awards
																			Equity
																	Equity		Incentive
																	Incentive		Plan
																	Plan		Awards:
							Equity										Awards:		Market or
							Incentive										Number		Payout
							Plan								Market		of		Value of
	Number			Number			Awards:						Number		Value		Unearned		Unearned
	of			of			Number						of Shares		of Shares		Shares,		Shares,
	Securities			Securities			of						or		or Units		Units or		Units or
	Underlying			Underlying			Securities						Units of		of		Other		Other
	Unexercised			Unexercised			Underlying						Stock		Stock		Rights		Rights
	Options			Options			Unexercised		Option		Option		That Have		That Have		That Have		That Have
	(#)			(#)			Unearned		Exercise		Expiration		Not		Not		Not		Not
Name	Exercisable			Unexercisable			Options		Price		Date		Vested		Vested		Vested		Vested
L. C. Oldham		7,500	(1)		30,000	(1)		0	$	4.97		06-20-11		0		0		0		0
E. A. Bayley		25,000			0			0	$	3.60		08-04-08		0		0		0		0
		50,000			0			0	$	4.97		06-20-11		0		0		0		0
J. S. Rutherford		44,000			0			0	$	4.97		06-20-11		0		0		0		0
D. E. Tiffin		0			0			0		0		0		0		0		0		0
S. D. Foster		0			0			0		0		0		0		0		0		0
T. R. Cambridge		0			0			0		0		0		0		0		0		0

(1) This stock option is exercisable with respect to 7,500 shares on the first day of January in each of the years 2007, 2008, 2009, 2010 and 2011.

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Option Exercises and Stock Vested in 2007

     In the table below, we show certain information about (i) the number of shares of common stock acquired upon exercise of stock options by each of the named executive officers in 2007 and the value realized on exercise of the stock options and (ii) stock awards.

	Option Awards					Stock Awards
	Number of					Number of
	Shares			Value		Shares		Value
	Acquired			Realized		Acquired		Realized
	on			on		on		on
Name	Exercise			Exercise(1)		Vesting		Vesting
Larry C. Oldham		46,000		$	661,020		0		0
Donald E. Tiffin		0		$	0		0		0
Eric A. Bayley		25,000		$	464,000		0		0
John S. Rutherford		2,000		$	31,980		0		0
		2,000		$	31,980		0		0
		2,000		$	29,780		0		0
Steven D. Foster		0		$	0		0		0
Thomas R. Cambridge		100,000		$	1,890,000		0		0
		1,707	(2)	$	26,015		0		0
		25,000	(2)	$	384,500		0		0
		26,707	(2)	$	361,079		0		0
		23,293	(2)	$	356,383		0		0
		23,293	(2)	$	312,592		0		0
		1,707	(2)	$	20,569		0		0
		50,000	(2)	$	636,000		0		0
		25,000	(2)	$	325,000		0		0
		23,293	(2)	$	283,010		0		0

(1)	The value realized on exercise is equal to the closing price of our common stock on the date of exercise, less the exercise price of the stock option exercised, multiplied by the number of shares acquired on exercise.
(2)	These shares were acquired by Mr. Cambridge during the period from August 23, 2007 to September 11, 2007 upon exercise of stock options following his retirement on June 26, 2007. All of the stock options exercised by Mr. Cambridge after his retirement would have expired by their own terms on September 26, 2007 had they not been exercised.

Potential Payments Upon Change of Control

     Stock Option Plans

     Our outstanding stock options and stock option plans contain certain change of control provisions which are applicable to our outstanding stock options, including the options held by our officers and Directors. For purposes of our options, a change of control occurs if:

• we are not the surviving entity in a merger or consolidation (or survive only as a subsidiary of another entity);

• we sell, lease or exchange all or substantially all of our assets;

• we dissolve and liquidate;

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• any person or group acquires beneficial ownership of more than 50% of our common stock; or

• in connection with a contested election of Directors, the persons who were Directors of Parallel before the election cease to constitute a majority of the Board of Directors.

     Under our 1992 Stock Option Plan and 2001 Employee Stock Option Plan, if a change of control occurs, the Compensation Committee of the Board of Directors can:

• accelerate the time at which options may be exercised;

• require optionees to surrender some or all of their options and pay to each optionee the change of control value;

• make adjustments to the options to reflect the change of control; or

• permit the holder of the option to purchase, instead of the shares of common stock as to which the option is then exercisable, the number and class of shares of stock or other securities or property which the optionee would acquire under the terms of the merger, consolidation or sale of assets and dissolution if, immediately before the merger, consolidation or sale of assets or dissolution, the optionee had been the holder of record of the shares of common stock as to which the option is then exercisable.

     The change of control value is an amount equal to, whichever is applicable:

• the per share price offered to our stockholders in a merger, consolidation, sale of assets or dissolution transaction;

• the price per share offered to our stockholders in a tender offer or exchange offer where a change of control takes place; or

• if a change of control occurs other than from a tender or exchange offer, the fair market value per share of the shares into which the options being surrendered are exercisable, as determined by the Committee.

     In the case of our 1997 Nonemployee Directors Stock Option Plan, 1998 Stock Option Plan and 2001 Nonemployee Director Stock Option Plan, upon the occurrence of a change of control, any outstanding options under these plans become fully exercisable and upon exercise of the option, the option holder will be entitled to purchase, instead of the numbers of shares of stock for which the option is then exercisable, the number and class of shares of stock or other securities or property to which the option holder would have been entitled under the terms of the change of control if, immediately before the change of control, the option holder had been the holder of record of the number of shares of stock for which the option is then exercisable.

     Incentive and Retention Plan

     On September 22, 2004, the Compensation Committee of the Board of Directors approved and adopted an incentive and retention plan for our officers and employees. On September 24, 2004, the Board of Directors adopted the plan upon recommendation by the Compensation Committee.

     The purpose of the plan is to advance the interests of Parallel and its stockholders by providing officers and employees with incentive bonus compensation which is linked to a corporate transaction. As defined in the plan, a corporate transaction means:

• an acquisition of us by way of purchase, merger, consolidation, reorganization or other business combination, whether by way of tender offer or negotiated transaction, as a result of which our outstanding securities are exchanged or converted into cash, property and/or securities not issued by us;

• a sale, lease, exchange or other disposition by us of all or substantially all of our assets;

• our stockholders approve a plan or proposal for our liquidation or dissolution; or

• any combination of any of the foregoing.

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      The plan recognizes the possibility of a proposed or threatened transaction and the need to be able to rely upon officers and employees continuing their employment, and that Parallel be able to receive and rely upon their advice as to the best interests of Parallel and its stockholders without concern that they might be distracted by the personal uncertainties and risks created by any such transaction. In this regard, the plan provides for a retention payment upon the occurrence of a change of control, as defined below.

     All members of Parallel’s “executive group” are participants in the plan. For purposes of the plan, the “executive group” includes Messrs. Oldham, Tiffin, Foster, Rutherford and Bayley and any other officer employee of Parallel selected by the Compensation Committee in its sole discretion. In addition, the Committee may designate other non-officer employees of Parallel and consultants to Parallel as participants in the plan who will also be eligible to receive a performance bonus upon the occurrence of a corporate transaction or a retention payment upon the occurrence of a change of control.

     Generally, the plan provides for:

• the payment of a one-time performance bonus to eligible officers and employees upon the occurrence of a corporate transaction; or

• a one time retention payment upon a change of control of Parallel. A change of control is generally defined as the acquisition of beneficial ownership of 60% or more of the voting power of Parallel’s outstanding voting securities by any person or group of persons, or a change in the composition of the Board of Directors of Parallel such that the individuals who, at the effective date of the plan, constitute the Board of Directors cease for any reason to constitute at least a majority of the Board of Directors.

     On August 23, 2005, the Compensation Committee of the Board of Directors of Parallel approved and adopted amendments to the incentive and retention plan, and on that same date, the Board of Directors approved the amendments upon recommendation by the Compensation Committee. Generally, the plan was amended to provide for 400,000 “additional base shares” with an associated “additional base price” of $8.62 per share. The plan was further amended on February 27, 2007 to expand the class of eligible participants to include consultants to Parallel.

     The amount of these payments depends on future prices of Parallel’s common stock, which is undeterminable until a triggering event occurs. In the case of a corporate transaction, the total cash obligation for performance bonuses is equal to the sum of (a) per share price received by all stockholders minus a base price of $3.73 per share, multiplied by 1,080,362 shares, plus (b) the per share price received by all stockholders minus an “additional base price” of $8.62 per share, multiplied by 400,000 “additional base shares”. As an example, if the stockholders of Parallel received the December 31, 2007 per share closing price of $17.63 in a merger, tender offer or other corporate transaction, the total aggregate potential payments to all plan participants would be [($17.63 — $3.73) x 1,080,362], plus [$17.63 — $8.62) x 400,000], or $18.6 million. If a change of control occurs, the total amount of cash retention payments to all plan participants would be equal to the sum of (a) per share closing price of Parallel’s common stock on the day immediately preceding the change of control minus the base price of $3.73 per share, multiplied by 1,080,362, plus (b) the per share closing price of Parallel’s common stock on the day immediately preceding the change of control minus an “additional base price” of $8.62 per share, multiplied by 400,000.

     If a corporate transaction or change of control occurs, the Compensation Committee will allocate for payment to each member of the executive group such portion of the total performance bonus or retention payment as the Compensation Committee determines in its sole discretion. After making these allocations, if any part of the total performance bonus or retention payment amount remains unallocated, the Compensation Committee may allocate any remaining portion of the performance bonus or retention payment among all other participants in the plan. After all allocations of the performance bonus have been made, each participant’s proportionate share of the performance bonus or retention payment will be paid in a cash lump sum.

     There is no certainty with respect to whether or when payments under this plan might be triggered, or the amount of any potential payment to any member of the executive group or other participants if a triggering event did occur.

     Our ultimate liability under the plan is not readily determinable because of the inability to predict the occurrence of a corporate transaction or change of control, or our stock price on the future date of any such corporate transaction or change of control. No liability will be recorded until such time as a corporate transaction or change of control becomes probable and the amount of the liability becomes determinable. The occurrence of a change of con-

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trol or a corporate transaction could have a negative impact on our financial condition and results of operations, depending upon the price of our common stock at the time of a change of control or corporate transaction.

     The plan is entirely unfunded and the plan makes no provision for segregating any of our assets for payment of any amounts under the plan.

     A participant’s rights under the plan are not transferable.

     The plan is administrated by the Compensation Committee of the Board of Directors of Parallel. The Compensation Committee has the power, in its sole discretion, to take such actions as may be necessary to carry out the provisions and purposes of the plan. The Compensation Committee has the authority to control and manage the operation and administration of the plan and has the power to:

• designate the officers and employees of, and consultants to, Parallel and its subsidiaries who participate in the plan, in addition to the “executive group”;

• maintain records and data necessary for proper administration of the plan;

• adopt rules of procedure and regulations necessary for the proper and efficient administration of the plan;

• enforce the terms of the plan and the rules and regulations it adopts;

• employ agents, attorneys, accountants or other persons; and

• perform any other acts necessary or appropriate for the proper management and administration of the plan.

     The plan automatically terminates and expires on the date participants receive a performance bonus or retention payment.

Non-Officer Severance Plan

     In January 2006, a Non-Officer Employee Severance Plan was implemented for the purpose of providing our non-officer employees with an incentive to remain employed by us. This plan provides for a one-time severance payment to non-officer employees equal to one year of their then current base salary upon the occurrence of a change of control within the meaning of the plan. Based on the aggregate non-officer base salaries in effect as of December 31, 2007, if a change of control had occurred at December 31, 2007, the total severance amount payable under this plan would have been approximately $3.8 million.

Compensation of Directors

     In addition to reviewing the compensation of our executive officers, the Compensation Committee also periodically reviews the compensation program for our four non-employee Directors, all of whom are members of the Compensation Committee. The last time Director compensation was modified was in June 2004. At its meeting held on February 12, 2008, the Committee authorized and approved the payment of an annual cash retainer fee in the amount of $50,000 for each non-employee Director, which will be paid in lieu of all other cash fees. The per meeting fees that we have been paying to our non-employee Directors for attendance at Board and Board committee meetings, and the fees paid for serving as Chairman of Board committees, were terminated effective January 1, 2008. The Committee is also currently reviewing and evaluating the equity component of Director compensation.

     Mr. Oldham, our only Director who is also an officer of Parallel, does not receive any compensation for his services as a member of the Board or the Board’s Hedging and Acquisitions Committee.

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     In the table below, we show certain information about the compensation paid to our non-employee Directors during 2007.

2007 Director Compensation

											Change in
	Fees										Pension
	Earned										Value and
	or								Non-Equity		Nonqualified
	Paid in			Stock		Option			Incentive Plan		Deferred		All Other
Name	Cash			Awards(1)		Awards(2)			Compensation		Compensation		Compensation		Total
D. E. Chitwood(3)	$	1,500		$	0	$	0			0		0		0	$	1,500
E. A. Nash	$	11,375		$	23,964	$	0			0		0		0	$	35,339
M .B. Oring	$	33,000		$	23,964	$	77,872			0		0		0	$	134,836
R.M . Poage	$	32,250		$	23,964	$	203,238	(4)		0		0		0	$	259,452
J.G. Shrader	$	41,750	(5)	$	23,964	$	77,872			0		0		0	$	143,586

(1)	On the first day of July of each year, beginning July 1, 2004, our non-employee directors are automatically granted shares of common stock having a value of $25,000. The actual number of shares granted is determined by dividing $25,000 by the average daily closing price of the common stock for ten consecutive trading days commencing fifteen trading days before the first day of July of each year. Under this plan, a total of 1,100 shares of common stock have been granted to Mr. Nash and each of Messrs. Oring, Poage and Shrader have been granted a total of 10,395 shares of common stock since inception of the plan, which includes 1,100 shares granted to each of them on the July 1, 2007 grant date. For the July 1, 2007 grant, the 1,100 shares were calculated by dividing $25,000 by $22.723, the ten trading day average closing price of the stock, beginning on June 18, 2007. Since July 1, 2007 was not a business day, the amount set forth in this column is based on the closing price of our common stock on July 2, 2007, the first business day following the grant date. The amounts shown in this column represent the dollar amount we recognized for financial statement reporting purposes with respect to the fiscal year ended December 31, 2007, computed in accordance with FAS 123R and also represents the aggregate grant date fair value computed in accordance with FAS 123R. Due to an inadvertent error in calculating the number of shares granted to each of our non-employee directors in 2007, each non-employee director received 39 more shares than the total of 1,061 shares that each non-employee director should have received. Our non-employee directors have agreed to offset against future cash fees the economic equivalent (approximately $919) of the additional 39 shares.
(2)	The amounts shown in this column represent the dollar amount we recognized for financial statement reporting purposes with respect to the fiscal year ended December 31, 2007, computed in accordance with FAS 123(R) of option awards made to the non-employee Directors prior to 2007 and the option award made to Mr. Poage in 2007 as further described in footnote (4) below. The amounts shown exclude the impact of estimated forfeitures. For a discussion of valuation assumptions, see Note 11 to our Consolidated Financial Statements included in this Annual Report on Form 10-K. For information about the aggregate number of stock options held by each of our nonemployee Directors, you should read the table below under the heading “Outstanding Equity Awards at 2007 Fiscal Year-End”.
(3)	Mr. Chitwood resigned from the Board of Directors on January 23, 2007.
(4)	On March 27, 2007, a stock option to purchase 17,500 shares of common stock was granted to Mr. Poage under the Parallel Petroleum Corporation 1997 Nonemployee Directors’ Stock Option Plan. The option becomes exercisable with respect to 8,750 shares on March 27, 2008 and the remaining 8,750 shares become exercisable on March 27, 2009. The grant date fair value of the option award, computed in accordance with FAS 123(R), was $217,898.
(5)	This amount includes $7,500 for Mr. Shrader’s service as Chairman of the Corporate Governance and Nominating Committee for 2004, 2005 and 2006 but paid in 2007.

     Narrative descriptions of the components of our Director compensation are included below under the captions “ — Cash”; “ — Stock Options”; “ — Other”; “ — 2004 Non-Employee Director Stock Grant Plan”; “ — Stock Option Plans — 1997 Nonemployee Directors Stock Option Plan” and “2001 Nonemployee Directors Stock Option Plan”.

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     In the table below, we show certain information about the outstanding equity awards held by our non-employee Directors at December 31, 2007.

Outstanding Equity Awards at 2007 Fiscal Year-End

			Option Awards											Stock Awards
																		Equity
																Equity		Incentive
																Incentive		Plan
																Plan		Awards:
						Equity										Awards:		Market or
						Incentive										Number		Payout
						Plan								Market		of		Value of
	Number		Number			Awards:						Number		Value		Unearned		Unearned
	of		of			Number						of Shares		of Shares		Shares,		Shares,
	Securities		Securities			of						or		or Units		Units or		Units or
	Underlying		Underlying			Securities						Units of		of		Other		Other
	Unexercised		Unexercised			Underlying						Stock		Stock		Rights		Rights
	Options		Options			Unexercised		Option		Option		That Have		That Have		That Have		That Have
	(#)		(#)			Unearned		Exercise		Expiration		Not		Not		Not		Not
Name	Exercisable		Unexercisable			Options		Price		Date		Vested		Vested		Vested		Vested
E. A. Nash		0		0			0		—		—		0		0		0		0
M.B. Oring		5,000		0			0	$	4.58		05-02-11		0		0		0		0
		25,000		0			0	$	4.97		06-21-11		0		0		0		0
		34,500		0			0	$	2.80		12-18-12		0		0		0		0
		20,000		0			0	$	4.61		05-07-11		0		0		0		0
		10,000		15,000	(1)		0	$	12.27		08-23-15		0		0		0		0
		10,000		15,000	(1)		0	$	12.27		08-23-15		0		0		0		0
R.M. Poage		50,000		0			0	$	2.61		04-28-13		0		0		0		0
		20,000		30,000	(2)		0	$	12.27		08-23-15		0		0		0		0
		0		17,500	(3)		0	$	22.89		03-27-17		0		0		0		0
J.G. Shrader		20,000		30,000	(2)		0	$	12.27		08-23-15		0		0		0		0

(1)	These stock options become exercisable with respect to 5,000 shares on the twenty-third day of August in each of the years 2008 through 2010.
(2)	These stock options become exercisable with respect to 10,000 shares on August 23, 2008 and on the twenty-third day of August in each of the years 2009 and 2010.
(3)	This stock option becomes exercisable with respect to 8,750 shares on March 27, 2008, and an additional 8,750 shares become exercisable on March 27, 2009.

Cash

     Following stockholder approval of the 2004 Non-Employee Director Stock Grant Plan in June 2004, we reduced by one-half the per meeting and annual cash fees we had been paying to our non-employee Directors. For 2007, we paid each non-employee Director a cash fee of $750 for attendance at each meeting of the Board of Directors and each non-employee Director who is a member of a Board committee also received:

• $375 per meeting for service on the Compensation Committee, with the Chairman of the Compensation Committee being entitled to receive an additional fee of $2,500 per year;

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• $375 per meeting for service on the Audit Committee, with the Chairman of the Audit Committee being entitled to receive an additional fee of $5,000 per year and each other Audit Committee member receiving $2,500 per year;

• $375 per meeting for service on the Corporate Governance and Nominating Committee, with the Chairman of the Corporate Governance and Nominating Committee being entitled to receive an additional fee of $2,500 per year; and

• $375 per meeting for service on the Hedging and Acquisitions Committee, with the Chairman of the Hedging and Acquisitions Committee being entitled to receive an additional fee of $2,500 per year.

      Stock Options

     Directors who are not employees of Parallel are also eligible to participate in Parallel’s 1997 Nonemployee Directors Stock Option Plan and the 2001 Nonemployee Directors Stock Option Plan. You can find more information about these stock option plans under the caption “Stock Option Plans” below.

      Other

     All Directors are reimbursed for expenses incurred in connection with attending meetings.

     Parallel provides liability insurance for its Directors and officers. The cost of this coverage for 2007 was approximately $524,000.

     We do not offer non-employee Directors travel accident insurance, life insurance or a pension or retirement plan.

      2004 Non-Employee Director Stock Grant Plan

     In April 2004, upon recommendation of the Board’s Compensation Committee, our Directors approved the 2004 Non-Employee Director Stock Grant Plan. The plan was later approved by our stockholders at our annual meeting held on June 22, 2004. Directors of Parallel who are not employees of Parallel or any of its subsidiaries are eligible to participate in the Plan. Under this Plan, each non-employee Director is entitled to receive an annual retainer fee consisting of shares of common stock that will be automatically granted on the first day of July in each year. The actual number of shares received is determined by dividing $25,000 by the average daily closing price of the common stock on the Nasdaq Global Market for the ten consecutive trading days commencing fifteen trading days before the first day of July of each year. Historically, Directors’ fees had been paid solely in cash. However, in accordance with this plan and following approval by our stockholders, we commenced paying an annual retainer fee in July 2004 to each non-employee Director in the form of common stock having a value of $25,000.

     This plan is administrated by the Compensation Committee. Although the Compensation Committee has authority to adopt such rules and regulations for carrying out the plan as it may deem proper and in the best interests of Parallel, the Committee’s administrative functions are largely ministerial in view of the plan’s explicit provisions described below, including those related to eligibility and predetermination of the timing, pricing and amount of grants. The interpretation by the Compensation Committee of any provision of the plan is final.

     The total number of shares of common stock initially available for grant under the plan was 116,000 shares, subject to adjustment as described below. If there is a change in the common stock by reason of a merger, consolidation, reorganization, recapitalization, stock dividend, stock split, combination of shares, exchange of shares, change in corporate structure or otherwise, the aggregate number of shares available under the plan will be appropriately adjusted in order to avoid dilution or enlargement of the rights intended to be made available under the plan.

     The Board may suspend, terminate or amend the plan at any time or from time to time in any manner that the Board may deem appropriate; provided that, without approval of the stockholders, no revision or amendment shall change the eligibility of Directors to receive stock grants, the number of shares of common stock subject to any grants, or materially increase the benefits accruing to participants under the plan, and plan provisions relating to the amount, price and timing of grants of stock may not be amended.

     Shares acquired under the plan are non-assignable and non-transferable other than by will or the laws of descent and distribution and may not be sold, pledged, hypothecated, assigned or transferred until the non-employee

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Director holding such stock ceases to be a Director, except that the Compensation Committee may permit a transfer of stock subject to the condition that the Compensation Committee receive evidence satisfactory to it that the transfer is being made for essentially estate and/or tax planning purposes or a gratuitous or donative purpose and without consideration.

     The plan will remain in effect until terminated by the Board, although no additional shares of common stock may be issued after the 116,000 shares subject to the plan have been issued.

     At February 8, 2008, 74,420 shares of common stock were available for issuance under this plan.

Stock Option Plans

     1992 Stock Option Plan. In May 1992, our stockholders approved and adopted the 1992 Stock Option Plan. The 1992 Plan expired by its own terms on March 1, 2002, but remains effective only for purposes of outstanding options. The 1992 Plan provided for granting to key employees, including officers and Directors who were also key employees of Parallel, and Directors who were not employees, options to purchase up to an aggregate of 750,000 shares of common stock. Options granted under the 1992 Plan to employees are either incentive stock options or options which do not constitute incentive stock options. Options granted to non-employee Directors are not incentive stock options.

     The 1992 Plan is administered by the Board’s Compensation Committee, none of whom were eligible to participate in the 1992 Plan, except to receive a one-time option to purchase 25,000 shares at the time he or she became a Director. The Compensation Committee selected the employees who were granted options and established the number of shares issuable under each option and other terms and conditions approved by the Compensation Committee. The purchase price of common stock issued under each option is the fair market value of the common stock at the time of grant.

     The 1992 Plan provided for the granting of an option to purchase 25,000 shares of common stock to each individual who was a non-employee Director of Parallel on March 1, 1992 and to each individual who became a nonemployee Director following March 1, 1992. Members of the Compensation Committee were not eligible to participate in the 1992 Plan other than to receive a nonqualified stock option to purchase 25,000 shares of common stock as described above.

     When the 1992 Plan expired on March 1, 2002, 65,000 shares of common stock remained authorized for issuance under the 1992 Plan. However, the 1992 Plan prohibited the grant of options after March 1, 2002. Consequently, no additional options are available for grant under the 1992 Plan.

     At February 8, 2008, options to purchase a total of 20,000 shares of common stock were outstanding under the 1992 Plan.

     1997 Nonemployee Directors Stock Option Plan. The 1997 Nonemployee Directors Stock Option Plan was approved by our stockholders at the annual meeting of stockholders held in May 1997. This plan provides for granting to Directors who are not employees of Parallel options to purchase up to an aggregate of 500,000 shares of common stock. Options granted under this plan are not incentive stock options within the meaning of the Internal Revenue Code.

     This plan is administered by the Compensation Committee of the Board of Directors. The Compensation Committee has sole authority to select the non-employee Directors who are to be granted options; to establish the number of shares which may be issued to non-employee Directors under each option; and to prescribe the terms and conditions of the options in accordance with the plan. Under provisions of the plan, the option exercise price must be the fair market value of the stock subject to the option on the grant due. Options are not transferable other than by will or the laws of descent and distribution and are not exercisable after ten years from the date of grant.

     The purchase price of shares as to which an option is exercised must be paid in full at the time of exercise in cash, by delivering to Parallel shares of stock having a fair market value equal to the purchase price, or a combination of cash and stock, as established by the Compensation Committee.

     Options may not be granted under this plan after March 27, 2007 and at December 31, 2007, there were no shares of common stock available for future option grants under this plan.

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     At February 8, 2008, options to purchase a total of 97,500 shares of common stock were outstanding under this plan.

     1998 Stock Option Plan. In June 1998, our stockholders adopted the 1998 Stock Option Plan. The 1998 Plan provides for the granting of options to purchase up to 850,000 shares of common stock. Stock options granted under the 1998 Plan may be either incentive stock options or stock options which do not constitute incentive stock options.

     The 1998 Plan is administered by the Compensation Committee of the Board of Directors. Members of the Compensation Committee are not eligible to participate in the 1998 Plan. Only employees are eligible to receive options under the 1998 Plan and the Compensation Committee selects the employees who are granted options and establishes the number of shares issuable under each option.

     Options granted to employees contain terms and conditions that are approved by the Compensation Committee. The Compensation Committee is empowered and authorized, but is not required, to provide for the exercise of options by payment in cash or by delivering to Parallel shares of common stock having a fair market value equal to the purchase price, or any combination of cash and common stock. The purchase price of common stock issued under each option must not be less than the fair market value of the common stock at the time of grant. Options granted under the 1998 Plan are not transferable other than by will or the laws of descent and distribution and are not exercisable after ten years from the date of grant.

     Options may not be granted under the 1998 Plan after March 11, 2008. However, at December 31, 2007, there were no shares of common stock available for future option grants under the 1998 Stock Option Plan.

     At February 8, 2008, options to purchase a total of 72,500 shares of common stock were outstanding under this plan.

     2001 Nonemployee Directors Stock Option Plan. The 2001 Nonemployee Directors Stock Option Plan was approved by our stockholders at the annual meeting of stockholders held in June 2001. This plan provides for granting to Directors who are not employees of Parallel options to purchase up to an aggregate of 500,000 shares of common stock. Options granted under the plan will not be incentive stock options within the meaning of the Internal Revenue Code.

     This plan is administered by the Compensation Committee of the Board of Directors. The Compensation Committee has sole authority to select the non-employee Directors who are to be granted options; to establish the number of shares which may be issued to non-employee Directors under each option; and to prescribe such terms and conditions as the Committee prescribes from time to time in accordance with the plan. Under provisions of the plan, the option exercise price must be the fair market value of the stock subject to the option on the grant date. Options are not transferable other than by will or the laws of descent and distribution and are not exercisable after ten years from the date of grant.

     The purchase price of shares as to which an option is exercised must be paid in full at the time of exercise in cash, by delivering to Parallel shares of stock having a fair market value equal to the purchase price, or a combination of cash and stock, as established by the Compensation Committee.

     Options may not be granted under this plan after May 2, 2011. However, at December 31, 2007, no shares of common stock were available for future option grants under this plan.

     At February 8, 2008, options to purchase 184,500 shares of common stock were outstanding under this plan.

     2001 Employee Stock Option Plan. In June 2001, our Board of Directors adopted the2001 Employee Stock Option Plan. This plan authorized the grant of options to purchase up to 200,000 shares of common stock, or less than 1.00% of our outstanding shares of common stock. Directors and officers are not eligible to receive options under this plan. Only employees are eligible to receive options. Stock options granted under this plan are not incentive stock options.

     This plan was implemented without stockholder approval.

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     The 2001 Employee Stock Option Plan is administrated by the Compensation Committee of the Board of Directors. The Compensation Committee selects the employees who are granted options and establishes the number of shares issuable under each option.

     Options granted to employees contain terms and conditions that are approved by the Compensation Committee. The Compensation Committee is empowered and authorized, but is not required, to provide for the exercise of options by payment in cash or by delivering to Parallel shares of common stock having a fair market value equal to the purchase price, or any combination of cash and common stock. The purchase price of common stock issued under each option must not be less than the fair market value of the common stock at the time of grant. Options granted under this plan are not transferable other than by will or the laws of descent and distribution.

     The Employee Stock Option Plan will expire on June 20, 2011. However, at December 31, 2007, no shares of common stock were available for future option grants under this plan.

     At February 8, 2008, options to purchase 183,000 shares of common stock were outstanding under this plan.

Section 401(k) Retirement Plan

     Effective January 1, 2005, we adopted a retirement plan qualifying under Section 401(k) of the Internal Revenue Code. This plan is designed to provide eligible employees with an opportunity to save for retirement on a tax-deferred basis. A third party acts as the plan’s administrator and is responsible for the day-to-day administration and operation of the plan. This plan is maintained on a yearly basis beginning on January 1 and ending on December 31 of each year.

     Each employee is eligible to participate in the plan as of the date of his or her employment. An employee may elect to have his or her compensation reduced by a specific percentage or dollar amount and have that amount contributed to the plan as a salary deferred contribution. A plan participant’s aggregate salary deferred contributions for a plan year may not exceed certain statutory dollar limits, which for 2007 was $15,500. In addition to the annual salary deferral limit, employees who reach age 50 or older during a calendar year can elect to take advantage of a catch-up salary deferral contribution which, for 2007, was $5,000.The amount deferred by a plan participant, and any earnings on that amount, are not subject to income tax until actually distributed to the participant.

     Each year, in addition to salary deferrals made by a participant, Parallel may contribute to the plan “safe harbor” contributions and discretionary matching contributions. Matching contributions, if made, will equal a uniform percentage of a participant’s salary deferrals. The Compensation Committee established a “safe harbor” profit sharing contribution of 3% and a discretionary matching contribution in an amount not to exceed 3% of a participant’s annual salary. Each participant will share in discretionary profit sharing contributions, if any, regardless of the amount of service completed by the participant during the applicable plan year.

     Each participant may direct the investment of his or her interest in the plan under established investment direction procedures setting forth the investment choices available to the participants. Each participant will be entitled to all of the participant’s account under the plan upon retirement after age 65. Each participant is at all times 100% vested in amounts attributed to the participant’s salary deferrals and to matching contributions and discretionary profit sharing contributions made by Parallel. The plan contains special provisions relating to disability and death benefits.

     Participants may borrow from their respective plan accounts, subject to the plan administrator’s determination that the participant submitting an application for a loan meets the rules and requirements set forth in the written loan program established by Parallel. Parallel has the right to amend the plan at any time. However, no amendment may authorize or permit any part of the plan assets to be used for purposes other than the exclusive benefit of participants or their beneficiaries.

     We make matching contributions to employee accounts in an amount equal to the contribution made by each employee, subject to a maximum of 6% of each employee’s salary during any calendar year. During 2007, we contributed an aggregate of $274,335 to the accounts of 45 employee participants. Of this amount, $19,800 was allocated to Mr. Oldham’s account; $10,500 was allocated to Mr. Bayley’s account; $10,500 was allocated to Mr. Rutherford’s account; $16,500 to Mr. Tiffin’s account; and $11,400 to Mr. Foster’s account.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

     The table below shows information as of February 14, 2008 about the beneficial ownership of common stock by: (1) each person known by us to own beneficially more than five percent of our outstanding common stock; (2) our five current executive officers named in the Summary Compensation Table on page 73; (3) each Director of Parallel; and (4) all of our executive officers and Directors as a group.

Name and Address	Amount and Nature			Percent
of	of			of
Beneficial Owner	Beneficial Ownership (1)			Class(2)
Larry C. Oldham 1004 N. Big Sp ring, Suite 400 Midland, Texas 79701		733,590	(3)		1.78	%
Donald E. Tiffin 1004 N. Big Sp ring, Suite 400 Midland, Texas 79701		24,350	(4)		*
Eric A. Bay ley 1004 N. Big Sp ring, Suite 400 Midland, Texas 79701		153,490	(5)		*
Steven D. Foster 1004 N. Big Sp ring, Suite 400 Midland, Texas 79701		16,000	(6)		*
John S. Rutherford 1004 N. Big Sp ring, Suite 400 Midland, Texas 79701		89,800	(7)		*
Edward A. Nash 16214 Lafone Spring, Texas 77379		1,100			*
Martin B. Oring 10817 Grande Blvd. West Palm Beach, Florida 33417		208,414	(8)		*
Ray M. Poage 4711 Meandering Way Colleyville, Texas 76034		109,213	(9)		*
Jeffrey G. Shrader 801 S. Filmore, Suite 600 Amarillo, Texas 79105		55,395	(10)		*
Dreman Value Management, L.L.C. 520 East Cooper Ave., Suite 230-4 Aspen, Colorado 81611		2,203,250	(11)		5.34	%
Neuberger Berman, Inc. 605 Third Avenue New York, New York 10158		4,115,645	(12)		9.98	%
Next Century Growth Investors, LLC 5500 Wayzata Blvd., Suite 1275 Minneapolis, Minnesota 55416		2,947,394	(13)		7.14	%
All Executive Officers and Directors as a Group(9 persons)		1,391,352	(14)		3.35	%

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*	Less than one percent.
(1)	Unless otherwise indicated, all shares of common stock are held directly with sole voting and investment powers.

(2)	Securities not outstanding, but included in the beneficial ownership of each such person, are deemed to be outstanding for the purpose of computing the percentage of outstanding securities of the class owned by such person, but are not deemed to be outstanding for the purpose of computing the percentage of the class owned by any other person. Shares of common stock that may be acquired within sixty days of February 8, 2008 upon exercise of outstanding stock options are deemed to be outstanding.
(3)	Includes 400,000 shares of common stock held indirectly through Oldham Properties, Ltd., a limited partnership, and as to which Mr. Oldham disclaims beneficial ownership. Also included are 15,000 shares of common stock underlying a presently exercisable stock option held by Mr. Oldham. At February 8, 2008, a total of 50,000 shares of common stock were pledged as collateral to secure repayment of loans.
(4)	Of the total number of shares shown, 9,350 shares are held indirectly through Mr. Tiffin’s individual retirement account.
(5)	Includes 75,000 shares of common stock underlying presently exercisable stock options. A total of 6,790 shares of common stock are held indirectly by Mr. Bayley through an Individual Retirement Account and 408(k) Plan. At February 8, 2008, a total of 40,000 shares of common stock were pledged as collateral to secure repayment of loans. The total number of shares shown excludes a warrant to purchase 200 shares of common stock.
(6)	Includes 400 shares of common stock held by Mr. Foster’s wife and 9,000 shares held in his 408(k) Plan.
(7)	Includes 44,000 shares of common stock underlying a presently exercisable stock option. At February 8, 2008, a total of 45,800 shares of common stock were pledged as collateral to secure repayment of loans.
(8)	Of the total number of shares shown, 15,500 shares are held directly by Mr. Oring’s wife; 82,019 shares are held by Wealth Preservation, LLC, a limited liability company owned and controlled by Mr. Oring and his wife; and 104,500 shares may be acquired by Mr. Oring upon exercise of stock options that are presently exercisable or that become exercisable within the next sixty days.
(9)	Includes 20,068 shares of common stock held indirectly by Mr. Poage through his individual retirement account. Also included are 78,750 shares that may be acquired upon exercise of stock options that are presently exercisable or that become exercisable within the next sixty days.
(10)	Includes 20,000 shares of common stock that may be acquired upon exercise of a presently exercisable stock option or that become exercisable within the next sixty days. At February 8, 2008, a total of 25,000 shares of common stock were pledged as collateral to secure repayment of loans.
(11)	As reported in Schedule 13G filed by Dreman Value Management, L.L.C., an investment advisor, with the Securities and Exchange Commission on February 14, 2008, Dreman Value Management, L.L.C., or “Dreman”, reported beneficial ownership of 2,203,250 shares of common stock. Of these shares, Dreman reported sole voting power with respect to 624,950 shares; shared voting power with respect to 22,900 shares and shared dispositive power with respect to 2,203,250 shares.
(12)	Based on Amendment No. 1 to Schedule 13G filed by Neuberger Berman, Inc., Neuberger Berman, LLC, Neuberger Berman Management, Inc. and Neuberger Berman Equity Funds with the Securities and Exchange Commission on February 12, 2008, Neuberger Berman, Inc. or “NBI”, reported beneficial ownership of 4,115,645 shares of common stock. Of these shares, NBI and Neuberger Berman, LLC each reported sole voting power with respect to 118,204 shares; shared voting power with respect to 3,067,141 shares; and shared dispositive power with respect to 4,115,645 shares. Neuberger Berman Management, Inc. reported shared voting and dispositive powers with respect to 3,067,145 shares and Neuberger Berman Equity Funds reported shared voting and dispositive powers with respect to 3,032,641 shares. NBI is the parent company of

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	Neuberger Berman, LLC, an investment advisor and broker-dealer, and Neuberger Berman Management Inc., an investment advisor to a series of public mutual funds. Neuberger Berman, LLC is deemed to be a beneficial owner of such shares since it has shared dispositive power, and in some cases the sole power to vote such shares. Neuberger Berman Management Inc. is deemed to be a beneficial owner of such shares since it has shared dispositive and voting power. The holdings of Lehman Brothers Asset Management LLC, an affiliate of Neuberger Berman LLC, are also included in the total number of shares shown.
(13)	Based on Schedule 13G filed by Next Century Growth Investors, LLC, Thomas L. Press and Donald M. Longlet with the Securities and Exchange Commission on February 14, 2008, Next Century Growth Investors, LLC, or “NCGI”, reported beneficial ownership of 2,947,394 shares of common stock. NCGI reported that it may be deemed to be the beneficial owner of such shares by virtue of its investment discretion and/or voting power over client securities, which may be revoked, and that Thomas L. Press and Donald M. Longlet may also be deemed to have beneficial ownership of such shares as a result of their positions with and ownership positions in NCGI, which could be deemed to confer upon each of them voting and/or investment power over the shares. Each of NCGI, Thomas L. Press and Donald M. Longlet disclaim beneficial ownership of such shares except to the extent of each of their respective pecuniary interests therein, if any.
(14)	Includes 337,250 shares of common stock underlying stock options that are presently exercisable or that become exercisable within the next sixty days.

Equity Compensation Plans

     At December 31, 2007, a total of 631,920 shares of common stock were authorized for issuance under our equity compensation plans. In the table below, we describe certain information about these shares and the equity compensation plans which provide for their authorization and issuance. You can find additional information about our stock grant and stock option plans beginning on page 84.

Equity Compensation Plan Information

						(c)
						Number of securities
				(b)		remaining available for
	(a)			Weighted-average		future issuance under
	Number of securities to be			exercise		equity compensation
	issued upon exercise of			price of outstanding		plans (excluding
	outstanding options,			options, warrants and		securities reflected in
Plan category	warrants and rights			rights		column (a))
Equity compensation plans approved by security holders		374,500	(1)	$	8.03		74,420	(2)
Equity compensation plans not approved by security holders		183,000	(3)	$	4.97		—
Total		557,500		$	7.03		74,420

(1)	Includes shares of common stock issuable upon exercise of stock options granted under our 1992 Stock Option Plan, 1997 Nonemployee Directors Stock Option Plan, 1998 Stock Option Plan, and 2001 Nonemployee Directors Stock Option Plan.
(2)	These shares of common stock are available for future issuance under our 2004 Non-Employee Director Stock Grant Plan.
(3)	These shares represent shares of common stock underlying stock options granted on June 20, 2001 to non-officer employees under our 2001 Employee Stock Option Plan. The 2001 Employee Stock Option Plan is the only equity compensation plan in effect that we have adopted without approval of our stockholders. Our directors and officers are not eligible to participate in this plan. A description of the material features of this plan can be found under the caption “2001 Employee Stock Option Plan” on page 85.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Certain Transactions

     During 2007, Cambridge Production, Inc., a corporation owned by Thomas R. Cambridge, our former Chairman of the Board of Directors, served as operator of two wells on oil and natural gas leases in which we acquired a working interest in 1984. Generally, the operator of a well is responsible for the day to day operations on the lease, overseeing production, employing field personnel, maintaining production and other records, determining the location and timing of drilling of wells, administering natural gas contracts, joint interest billings, revenue distribution, making various regulatory filings, reporting to working interest owners and other matters. During 2007, Cambridge Production billed us approximately $27,000 for our pro rata share of lease operating expenses. The largest amount we owed Cambridge Production at any one time during 2007 was approximately $6,400. As of December 31, 2007, approximately $750 was owed by us to Cambridge Production for these expenses. Our pro rata share of oil and natural gas sales during 2007 from the wells operated by Cambridge Production was approximately $65,000. Cambridge Production’s billings to us are made monthly on the same basis as all other working interest owners in the wells.

     Cambridge Partnership, Ltd., a limited partnership controlled by Mr. Cambridge, acquired an undivided working interest in 1999 from us in an oil and natural gas prospect located in south Texas. The interest was acquired on the same terms as all other unaffiliated working interest owners. Since then, Cambridge Partnership, Ltd. has participated with us in the drilling and development of this prospect. Cambridge Partnership, Ltd. has participated in these operations under standard form operating agreements on the same or similar terms afforded by Parallel to nonaffiliated third parties. Although we are not the operator of this project, we invoiced Cambridge Partnership, Ltd., on a monthly basis, without interest, for its pro rata share of operating expenses. During 2007, we billed Cambridge Partnership, Ltd. approximately $1,300 for its proportionate share of lease operating expenses incurred on properties we administer, and Cambridge Partnership, Ltd. paid us approximately $1,600 for its proportionate share of lease operating expenses, which included approximately $285 attributable to expenses billed to Cambridge Partnership, Ltd. in 2006. The largest amount owed to us by Cambridge Partnership, Ltd. at any one time during 2007 for its share of lease operating expenses was approximately $300. At December 31, 2007, no amount was owed us by Cambridge Partnership, Ltd. for these expenses. During 2007, we disbursed approximately $4,600 to Cambridge Partnership, Ltd. in payment of revenues attributable to its pro rata share of the proceeds from sales of oil and natural gas produced from properties in which we and Cambridge Partnership, Ltd. owned interests. We and Cambridge Partnership, Ltd. sold our interests in this project in June 2007 to an unaffiliated third party and we distributed approximately $10,000 to Cambridge Partnership, Ltd., its pro rata share of the sales proceeds.

     Cambridge Production, Inc. maintains an office in Amarillo, Texas from which Mr. Cambridge performed his duties and services as Chairman of the Board and as geological consultant to us until his retirement on June 26, 2007. Prior to his retirement, we reimbursed Cambridge Production, Inc. $3,000 per month for office and administrative expenses incurred on our behalf. During 2007 we reimbursed Cambridge Production, Inc. a total of $18,000.

     In December 2001, and prior to his employment by us, Donald E. Tiffin, our Chief Operating Officer, received from an unaffiliated third party a 3% working interest in our Diamond M project in Scurry County, Texas for services rendered in connection with assembling the project. In August 2002, shortly after his employment with us, and due to the personal financial exposure in the Diamond M project and to prevent the interest from being acquired by a third party, Mr. Tiffin assigned two-thirds of his ownership interest in the project to us at no cost, leaving him with a 1% working interest. We acquired our initial interest in the Diamond M Project from the same third party in December 2001, but did not become operator of the project until March 1, 2003. As with other nonaffiliated interest owners, we invoice Mr. Tiffin on a monthly basis, without interest, for his share of drilling, development and lease operating expenses. During 2007, we billed Mr. Tiffin a total of approximately $45,000 for his proportionate share of capital expenditures and lease operating expenses, and Mr. Tiffin paid us approximately $47,000 for these drilling and development expenses, which included approximately $8,000 attributable to expenses billed to Mr. Tiffin in 2006. During 2007, we disbursed to Mr. Tiffin approximately $65,000 in oil and natural gas revenues related to his interest in this project. The largest aggregate amount outstanding and owed to us by Mr. Tiffin at any one time during 2007 was approximately $11,000. At December 31, 2007, Mr. Tiffin owed us approximately $5,000.

     We believe the transactions described above were made on terms no less favorable than if we had entered into the transactions with an unrelated party.

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Director Independence

     Under the Delaware General Corporation Law and our bylaws, Parallel’s business, property and affairs are managed by or under the direction of the Board of Directors. Members of the Board are kept informed of our business through discussions with the Chairman of the Board, the Chief Executive Officer and other officers, by reviewing materials provided to them and by participating in meetings of the Board and its committees. In 2007, seven individuals served as a Director of Parallel for all or a portion of the year. These individuals included Thomas R. Cambridge, Dewayne E. Chitwood, Edward A. Nash, Larry C. Oldham, Martin B. Oring, Ray M. Poage and Jeffrey G. Shrader. Mr. Chitwood resigned from the Board on January 23, 2007 and Mr. Cambridge retired from the Board on June 26, 2007 in accordance with our retirement policy for non-employee Directors. Under this retirement policy, a non-employee Director may not stand for re-election at the annual meeting of stockholders following the date on which he or she attains age 72. Mr. Cambridge, a Director of Parallel since 1985, turned age 72 before the date of the 2007 annual meeting of stockholders and, consequently, did not stand for re-election at the 2007 annual meeting. Mr. Nash was first elected as a Director at the 2007 annual meeting of stockholders. Messrs. Nash, Oldham, Oring, Poage and Shrader continue to serve as Directors.

     The Board has determined that Messrs. Nash, Oring, Poage and Shrader meet the definition of an “independent director” for the purposes of NASD Rule 4200(a)(15), the independence standards applicable to us, and that Mr. Chitwood was also an independent director . The Board based these determinations primarily on responses of the Directors to questions regarding employment and compensation history, affiliations and family and other relationships, comparisons of the independence criteria under NASD Rule 4200(a)(15) to the particular circumstances of each Director and on discussions among the Directors.

Procedures for Reviewing Certain Transactions

     We have adopted a written policy for the review, approval or ratification of related party transactions. All of our officers, directors and employees are subject to this policy. Under this policy, the Audit Committee reviews all related party transactions for potential conflicts of interest situations. Generally, our policy defines a “related party transaction” as a transaction in which we are a participant and the amount involved exceeds $10,000, and in which a related party has an interest. A “related party” is:

• a director or officer of Parallel or a nominee to become a director;

• an owner of more than 5% of our outstanding common stock;

• certain family members of any of the above persons; and

• any entity in which any of the above persons is employed or is a partner or principal or in which such person has a 5% or greater ownership interest.

     Approval Procedures

     Before entering into a related party transaction, the related party or the department within Parallel responsible for the potential transaction must notify the Audit Committee of the facts and circumstances of the proposed transaction, including:

• the related party’s relationship to Parallel and interest in the transaction;

• the material terms of the proposed transaction;

• the benefits to Parallel of the proposed transaction;

• the availability of other sources of comparable properties or services; and

• whether the proposed transaction is on terms comparable to terms available to an unrelated third party or to employees generally.

     The Audit Committee will then consider all of the relevant facts and circumstances available to it, including the matters described above and, if applicable, the impact on a Director’s independence. No member of the Audit Committee is permitted to participate in any review, consideration or approval of any related party transaction if

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such member or any of his or her immediate family members is the related party. After review, the Audit Committee may approve, modify or disapprove the proposed transaction. The Audit Committee will approve only those related party transactions that are in, or are not inconsistent with, the best interests of Parallel and its stockholders.

     Ratification Procedures

     If an officer or Director of Parallel becomes aware of a related party transaction that has not been previously approved or ratified by the Audit Committee then, if the transaction is pending or ongoing, the transaction must be submitted to the Audit Committee and the Audit Committee will consider the matters described above. Based on the conclusions reached, the Audit Committee will evaluate all options, including ratification, amendment or termination of the related party transaction. If the transaction is completed, the Audit Committee will evaluate the transaction, taking into account the same factors as described above, to determine if rescission of the transaction or any disciplinary action is appropriate, and will request that we evaluate our controls and procedures to determine the reason the transaction was not submitted to the Audit Committee for prior approval and whether any changes to the procedures are recommended.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

     The Audit Committee had not, as of the time of filing this Annual Report on Form 10-K with the Securities and Exchange Commission, adopted policies and procedures for pre-approving audit or permissible non-audit services performed by our independent auditors. Instead, the Audit Committee as a whole pre-approves all such services. In the future, our Audit Committee may approve the services of our independent auditors pursuant to pre-approval policies and procedures adopted by the Audit Committee, provided the policies and procedures are detailed as to the particular service, the Audit Committee is informed of each service, and such policies and procedures do not include delegation of the Audit Committee’s responsibilities to our management.

          The aggregate fees for professional services rendered by our principal accountants, BDO Seidman, LLP, for 2007 and 2006 were:

Types of Fees	2007		2006
	($ in thousands)
Audit fees(1)	$	736	$	469
Audit-related fees		13		52
Tax fees		—		—
All other fees		—		—
Total	$	749	$	521

(1) Includes fees for professional services rendered in connection with the audit of our internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act of 2002 in the amounts of $175,000 and $160,000 for 2007 and 2006, respectively.

     We retained an independent third party to assist us in our Sarbanes-Oxley 404 readiness and assessment of internal control over financial reporting. The aggregate fees for services provided in connection with the internal control over financial reporting for 2007 and 2006 were approximately $75,000 and $65,000, respectively, including associated expenses.

     In the above table, “audit fees” are fees we paid for professional services for the audit of our Consolidated Financial Statements included in our Annual Report on Form 10-K and for the review of our Consolidated Financial Statements included in our Quarterly Reports on Form 10-Q, or for services that are normally provided by our principal accountants in connection with statutory and regulatory filings or engagements and fees for Sarbanes-Oxley 404 audit work. “Audit-related fees” are fees billed for assurance and related regulatory filings.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as part of this report:

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules

For a list of Consolidated Financial Statements and Schedules, see “Index to the Consolidated Financial Statements” on page F-1, and incorporated herein by reference.

(a)(3) Exhibits

See Item 15(b) below.

(b) Exhibits:

A list of exhibits to this Annual Report on Form 10-K is set forth below.

No.	Description of Exhibit
3.1	Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)
3.2	Bylaws of Registrant (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on November 30, 2007)
3.3	Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
3.4	Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.4 of the Registrant’s Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
3.5	Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.5 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
3.6	Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
4.1	Certificate of Designations, Preferences and Rights of Serial Preferred Stock — 6% Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)
4.2	Certificate of Designations, Preferences and Rights of Series A Preferred Stock (Incorporated by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000)
4.3	Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the Registrant filed with the Securities and Exchange Commission on October 10, 2000)
4.4	Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No. 4.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
4.5	Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
4.6	Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

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No.	Description of Exhibit
4.7	Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American Stock Transfer, Inc. (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
4.8	First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant, Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
4.9	Form of Rule 144A 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
4.10	Form of IAI 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
4.11	Form of Regulation S 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
4.12	Indenture, dated as of July 31, 2007, among the Registrant as Issuer and Wells Fargo Bank, National Association as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
4.13	Registration Rights Agreement, dated as of July 31, 2007, by and among the Registrant, Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities Corp. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
4.14	Purchase Agreement, dated as of July 26, 2007, by and among the Registrant, Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities Corp. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
4.15	Form of 101/4% Unrestricted Senior Note due 2014 (Incorporated by reference to Exhibit 4.13 of Form S-4 of the Registrant, Registration No. 333-148465)
	Executive Compensation Plans and Arrangements (Exhibit No.’s 10.1 through 10.7):
10.1	1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
10.2	Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form 10-K for the fiscal year ended December 31, 1995)
10.3	Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005)
10.4	1998 Stock Option Plan (Incorporated by reference to Exhibit 10.4 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.5	2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form 10-Q Report for the fiscal quarter ended March 31, 2004)
10.6	2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated September 22, 2004)
10.7	Incentive and Retention Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.8	First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the Registrant, dated December 20, 2002)

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No.	Description of Exhibit
10.9	Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December 20, 2002)
10.10	First Amendment to First Amended and Restated Credit Agreement, dated as of September 12, 2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003)
10.11	Second Amended and Restated Credit Agreement, dated September 27, 2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated September 27, 2004 and filed with the Securities and Exchange Commission on October 1, 2004)
10.12	Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
10.13	First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27, 2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated December 30, 2004 and filed with the Securities and Exchange Commission on December 30, 2004)
10.14	Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated April 4, 2005 and filed with the Securities and Exchange Commission on April 8, 2005)
10.15	Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated October 4, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.16	Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy, Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney, Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit 10.2 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.17	Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.18	Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.19	ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank, N.A. (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.20	Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas, CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrant’s Form 8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on December 30, 2005)

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No.	Description of Exhibit
10.21	Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.4 of the Registrant’s Form 8-K Report, dated November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005)
10.22	Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas, N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C. (Incorporated by reference to Exhibit No. 10.5 of the Registrant’s Form 8-K Report, dated November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005)
10.23	Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.23 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.24	Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.24 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.25	Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.26	Third Amendment to Third Amended and Restated Credit Agreement, dated as of July 31, 2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
10.27	Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of November 30, 2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to Exhibit 10.27 of Form S-4 of the Registrant, Registration No. 333-148465)
*10.28	Hagerman Gas Gathering System Joint Venture Agreement, dated as of January 16, 2007, among the Registrant, Feagan Gathering Company and Capstone Oil and Gas Company, L.P.
14	Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrant’s Form 10-K Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange Commission on March 22, 2004)
*23.1	Consent of BDO Seidman, LLP
*23.2	Consent of Cawley Gillespie & Associates Inc. Independent Petroleum Engineers
*31.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes — Oxley Act of 2002.
*31.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes — Oxley Act of 2002.
*32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.
*32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.

* Filed herewith.

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PARALLEL PETROLEUM CORPORATION

Index to the Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm	F-2
Financial Statements:
Consolidated Balance Sheets at December 31, 2007 and 2006	F-3
Consolidated Statements of Operations for the years ended December 2007, 2006, and 2005	F-4
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2007, 2006 and 2005	F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005	F-6
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2007, 2006, and 2005	F-7
Notes to Consolidated Financial Statements	F-8

All schedules are omitted, as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or related notes.

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors
Parallel Petroleum
Corporation Midland, Texas

We have audited the accompanying consolidated balance sheets of Parallel Petroleum Corporation as of December 31, 2007 and 2006 and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Parallel Petroleum Corporation at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Parallel Petroleum Corporation’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 20, 2008, expressed an unqualified opinion thereon.

BDO Seidman, LLP
Houston, Texas

February 20, 2008

F-2

PARALLEL PETROLEUM CORPORATION
Consolidated Balance Sheets
December 31, 2007 and 2006
(dollars in thousands)

	2007			2006
Assets
Current assets:
Cash and cash equivalents	$	7,816		$	5,910
Accounts receivable:
Oil and natural gas sales		20,499			18,605
Joint interest owners and other, net of allowance for doubtful account of $50 and $80		2,460			7,212
Affiliates		3,970			3,335
		26,929			29,152
Other current assets		600			2,863
Deferred tax asset		10,293			4,340
Total current assets		45,638			42,265
Property and equipment, at cost:
Oil and natural gas properties, full cost method (including $86,402 and $50,375 not subject to depletion)		648,576			501,405
Other		2,877			2,614
		651,453			504,019
Less accumulated depreciation, depletion and amortization		(145,482	)		(115,513	)
Net property and equipment		505,971			388,506
Restricted cash		78			325
Investment in pipelines and gathering system ventures		8,638			6,454
Other assets, net of accumulated amortization of $1,425 and $760		2,768			5,268
	$	563,093		$	442,818
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	47,848		$	36,171
Asset retirement obligations		598			701
Derivative obligations		30,424			14,109
Total current liabilities		78,870			50,981
Revolving credit facility		60,000			115,000
Term loan		—			50,000
Senior notes (principal amount $150,000 in 2007)		145,383			—
Asset retirement obligations		4,339			4,362
Derivative obligations		13,194			14,386
Deferred tax liability		26,045			24,307
Total long-term liabilities		248,961			208,055
Commitments and contingencies (Note 15)
Stockholders’ equity:
Series A preferred stock — par value $0.10 per share, authorized 50,000 shares		—			—
Common stock — par value $0.01 per share, authorized 60,000,000 shares, issued and outstanding 41,252,644 and 37,547,010		412			375
Additional paid-in capital		196,457			140,353
Retained earnings		38,393			43,054
Total stockholders’ equity		235,262			183,782
	$	563,093		$	442,818

See accompanying Notes to Consolidated Financial Statements.

F-3

PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Operations
Years ended December 31, 2007, 2006 and 2005
(dollars in thousands, except per share data)

	2007			2006			2005
Oil and natural gas revenues:
Oil and natural gas sales	$	116,031		$	97,025		$	66,150
Cost and expenses:
Lease operating expense		22,200			16,819			9,947
Production taxes		5,545			5,577			4,102
Production tax refund		(1,209	)		—			—
General and administrative		10,415			9,523			6,712
Depreciation, depletion and amortization		30,115			24,687			12,044
Total costs and expenses		67,066			56,606			32,805
Operating income		48,965			40,419			33,345
Other income (expense), net:
Gain (loss) on derivatives not classified as hedges		(36,776	)		2,802			(31,669	)
Gain (loss) on ineffective portion of hedges		—			626			(137	)
Interest and other income		197			158			167
Interest expense		(19,177	)		(12,360	)		(4,780	)
Cost of debt retirement		(760	)		—			—
Other expense		(118	)		(189	)		(102	)
Equity in income (loss) of pipelines and gathering system ventures		(311	)		8,593			(89	)
Total other income (expense), net		(56,945	)		(370	)		(36,610	)
Income (loss) before income taxes		(7,980	)		40,049			(3,265	)
Income tax benefit (expense)		3,319			(13,894	)		1,676
Net income (loss)		(4,661	)		26,155			(1,589	)
Cumulative preferred stock dividend		—			—			(271	)
Net income (loss) available to common stockholders	$	(4,661	)	$	26,155		$	(1,860	)
Net income (loss) per common share:
Basic	$	(0.12	)	$	0.73		$	(0.06	)
Diluted	$	(0.12	)	$	0.71		$	(0.06	)

See accompanying Notes to Consolidated Financial Statements.

F-4

Consolidated Statements of Stockholders’ Equity
Years ended December 31, 2007, 2006 and 2005
(amounts in thousands)

																	Accumulated
	Preferred stock						Common stock				Additional						Other			Total
	Number of						Number of				paid-in			Retained			Comprehensive			stockholders’
	shares			Amount			shares		Amount		capital			earnings			Loss			equity
Balance, January 1, 2005		950		$	95			25,439	$	254	$	48,328		$	18,759		$	(7,442	)		59,994
Common stock issued, net of transaction costs		—			—			5,750		58		27,686			—			—			27,744
Common stock issued for services		—			—			12		—		99			—			—			99
Preferred stock converted		(950	)		(95	)		2,714		27		68			—			—			—
Cashless exercise of warrants		—			—			120		1		(1	)		—			—			—
Options exercised		—			—			714		7		2,241			—			—			2,248
Stock option expense		—			—			—		—		278			—			—			278
Changes in fair value of cash flow hedges, net of tax		—			—			—		—		—			—			999			999
Net loss		—			—			—		—		—			(1,589	)		—			(1,589	)
Dividends on preferred stock ($0.60 per share)		—			—			—		—		—			(271	)		—			(271	)
Balance, January 1, 2006		—		$	—			34,749	$	347	$	78,699		$	16,899		$	(6,443	)	$	89,502
Common stock issued, net of transaction costs		—			—			2,500		25		60,242			—			—			60,267
Common stock issued for services		—			—			5		—		118			—			—			118
Cashless exercise of warrants		—			—			117		1		(1	)		—			—			—
Options exercised		—			—			176		2		764			—			—			766
Stock option expense		—			—			—		—		531			—			—			531
Changes in fair value of cash flow hedges, net of tax		—			—			—		—		—			—			6,443			6,443
Net income		—			—			—		—		—			26,155			—			26,155
Balance, January 1, 2007		—		$	—			37,547	$	375	$	140,353		$	43,054		$	—		$	183,782
Common stock issued, net of transaction costs		—			—			3,000		30		52,492			—			—			52,522
Common stock issued for services		—			—			4		—		96			—			—			96
Cashless exercise of warrants		—			—			83		1		(1	)		—			—			—
Options exercised		—			—			619		6		2,454			—			—			2,460
Stock option expense		—			—			—		—		247			—			—			247
Tax benefit of stock option exercise in excess of compensation		—			—			—		—		816			—			—			816
Net loss		—			—			—		—		—			(4,661	)		—			(4,661	)
Balance, December 31, 2007		—		$	—			41,253	$	412	$	196,457		$	38,393		$	—		$	235,262

See accompanying Notes to Consolidated Financial Statements.

F-5

PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Cash Flows
Years ended December 31, 2007, 2006 and 2005
( dollars in thousands)

	2007			2006			2005
Cash flows from operating activities:
Net income (loss)	$	(4,661	)	$	26,155		$	(1,589	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		30,115			24,687			12,044
Gain on sale of automobiles		(30	)		—			—
Accretion of asset retirement obligation		324			248			112
Accretion of senior notes discount		197			—			—
Deferred income tax (benefit) expense		(3,319	)		13,894			(1,676	)
(Gain) loss on derivatives not classified as hedges		36,776			(2,802	)		31,669
(Gain) loss on ineffective portion of hedges		—			(626	)		137
Cost of debt retirement		760			—			—
Common stock issued in lieu of cash for directors fees		96			118			99
Stock option expense		247			531			278
Equity (income) loss in pipelines and gathering system ventures		311			(8,593	)		89
Return on investment in pipelines and gathering system ventures		287			9,000			—
Bad debt expense		(30	)		71			—
Changes in assets and liabilities:
Other assets, net		379			1,567			(823	)
Restricted cash		247			(50	)		(274	)
Decrease (increase) in accounts receivable		2,253			(15,151	)		(7,034	)
Decrease (increase) in other current assets		1,070			(153	)		(1,187	)
Increase in accounts payable and accrued liabilities		11,597			25,330			5,273
Federal tax deposit		—			(40	)		—
Net cash provided by operating activities		76,619			74,186			37,118
Cash flows from investing activities:
Additions to oil and natural gas properties		(149,298	)		(195,396	)		(77,351	)
Use of restricted cash for acquisition of oil and natural gas properties		—			2,366			(79	)
Proceeds from disposition of oil and natural gas properties and other property and equipment		1,677			130			3,028
Additions to other property and equipment		(379	)		(210	)		(342	)
Settlements of derivative instruments		(16,615	)		(3,902	)		(5,022	)
Purchase of derivative instruments		—			—			(2,363	)
Investment in pipelines and gathering system ventures		(2,782	)		(11,260	)		(2,820	)
Return of investment in pipelines and gathering system ventures		—			7,724			—
Net cash used in investing activities		(167,397	)		(200,548	)		(84,949	)
Cash flows from financing activities:
Borrowings from bank line of credit		92,000			117,000			45,714
Payments on bank line of credit		(147,000	)		(52,000	)		(74,714	)
Borrowings from term loan		—			—			50,000
Payment on term loan		(50,000	)		—			—
Senior notes (principal amount $150,000 in 2007)		145,186			—			—
Deferred financing costs		(813	)		(179	)		(1,253	)
Deferred debt offering		(1,671	)		—			—
Proceeds from exercise of stock options		2,460			766			2,248
Proceeds (net) from common stock issued		52,522			60,267			27,744
Payment of preferred stock dividend		—			—			(271	)
Net cash provided by financing activities		92,684			125,854			49,468
Net increase (decrease) in cash and cash equivalents		1,906			(508	)		1,637
Cash and cash equivalents at beginning of year		5,910			6,418			4,781
Cash and cash equivalents at end of year	$	7,816		$	5,910		$	6,418
Non-cash financing and investing activities:
Oil and natural gas properties asset retirement obligation	$	(450	)	$	2,320		$	251
Non-cash exchange of oil and natural gas properties:
Properties received in exchange	$	6,463		$	—		$	—
Properties delivered in exchange	$	(5,495	)	$	—		$	—
Other transactions:
Interest paid	$	13,096		$	12,255		$	5,192

See accompanying Notes to Consolidated Financial Statements.

F-6

PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Comprehensive Income (Loss)
Years ended December 31, 2007, 2006 and 2005
(dollars in thousands)

	2007			2006			2005
Net income (loss)	$	(4,661	)	$	26,155		$	(1,589	)
Other comprehensive income (loss):
Unrealized losses on derivatives		—			(1,648	)		(10,980	)
Reclassification adjustment for losses on derivatives included in net income (loss)		—			11,409			12,494
Change in fair value of derivatives		—			9,761			1,514
Income tax expense, deferred		—			(3,318	)		(515	)
Total other comprehensive income		—			6,443			999
Total comprehensive income (loss)	$	(4,661	)	$	32,598		$	(590	)

See accompanying Notes to Consolidated Financial Statements.

F-7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Organization, Business and Summary of Significant Accounting Policies

(a)	Basis of Consolidation
	The accompanying financial statements present the consolidated accounts of Parallel Petroleum Corporation, a Delaware Corporation, and its wholly owned subsidiaries, Parallel L.P. and Parallel, L.L.C. (collectively “the Company” or Parallel) prior to their dissolution and merger into Parallel on July 2, 2007. All significant inter-company account balances and transactions have been eliminated.
	The Company accounts for its interests in oil and natural gas joint ventures and working interests using the proportionate consolidation method. Under this method, the Company records its proportionate share of assets, liabilities, revenues and expenses.

(b)

Nature of Operations

The Company’s focus is on the acquisition, development and exploitation of long-lived oil and natural gas reserves and, to a lesser extent, exploration for new oil and natural gas reserves. The Company’s business activities are currently carried out primarily in Texas and New Mexico. The Company’s activities are focused in the Permian Basin of west Texas and New Mexico, the Fort Worth Basin of north Texas and the onshore Gulf Coast area of south Texas. The Company is actively evaluating, drilling and preparing to drill new projects located in the Cotton Valley Reef trend of east Texas and the Uinta Basin of Utah.

(c)

Concentration of Credit Risk

Financial instruments that potentially expose the Company to concentrations of credit risk consist primarily of unsecured accounts receivable from working interest owners and crude oil and natural gas purchasers. A substantial portion of Parallel’s oil and natural gas reserves are located in the Permian Basin and the Company may be disproportionally exposed to the impact of delays or interruptions of production from these wells due to mechanical problems, damages to the current producing reservoirs and significant governmental regulation, including any curtailment of production or interruption of transportation of oil or natural gas produced from the wells.

(d)	Property and Equipment
	Oil and natural gas properties:
	The Company uses the full cost method of accounting for its oil and natural gas producing activities. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves, including directly related overhead costs, are capitalized.
	Management and service fees received under contractual arrangements, if any, are treated as reimbursement of costs, offsetting the costs incurred to provide those services. Specifically, the Company serves as operator of certain oil and natural gas properties in which it owns an interest. Under operating agreements naming the Company as operator, the Company is reimbursed for certain specified direct charges and overhead charges. Amounts received in reimbursement for drilling activities are applied as a reduction to Parallel’s capital costs, and amounts received in reimbursement for producing activities are applied to reduce the Company’s general and administrative expenses.
	Depletion is provided using the unit-of-production method based upon estimates of proved oil and natural gas reserves with oil and natural gas production being converted to a common unit of measure based upon their relative energy content. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool and amortization begins. The amortizable base includes es-

F-8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

timated future development costs and where significant, dismantlement, restoration and abandonment costs, net of estimated salvage value.

In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas reserves are established based on estimates made by the Company's geologists and engineers which require significant judgment as does the projection of future production volumes and levels of future costs, including future development costs. In addition, considerable judgment is necessary in determining when unproved properties become impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may have significant impact on the calculation of depletion expense. There have been no material changes in the methodology used by the Company in calculating depletion of oil and gas properties under the full cost method during the three years ended December 31, 2007.

If the net investment in oil and natural gas properties in a cost center, net of related deferred taxes, exceeds an amount equal to the sum of (1) the standardized measure of discounted future net cash flows from proved reserves, as adjusted for estimated future asset retirement costs (see Note 16) and (2) the lower of cost or fair market value of properties in process of development and unexplored acreage, the excess is charged to expense as additional depletion and is separately disclosed during the period to which this excess occurs. The standardized measure is calculated using a 10% discount rate and is based on unescalated prices in effect at period-end with effect given to the Company’s cash flow hedge positions.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves, in which case the gain or loss would be recognized in the statement of operations.

Other Property and Equipment:

Maintenance and repairs are charged to operations. Renewals and betterments are capitalized to the appropriate property and equipment accounts.

Upon retirement or disposition of assets other than oil and natural gas properties, the cost and related accumulated depreciation are removed from the accounts with the resulting gains or losses, if any, recognized in the statement of operations. Depreciation of other property and equipment is computed using the straight-line method based on the estimated useful lives of the property and equipment.

(e)	Income Taxes
	The Company accounts for income taxes using the liability method. Under the liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under the liability method, the effect on previously recorded deferred tax assets and liabilities resulting from a change in tax rates is recognized in earnings in the period in which the change is enacted.
	The Company adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109” (“FIN 48”), on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement 109, “Accounting for Income Taxes”, and prescribes a recognition threshold and measurement process for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.
	Based on its evaluation, the Company has concluded that there are no significant uncertain tax positions requiring recognition in its financial statements. The Company’s evaluation was performed for the tax

F-9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

years ended December 31, 2003, 2004, 2005 and 2006, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2007.

The Company may from time to time be assessed interest or penalties by major tax jurisdictions, although any such assessments historically have been minimal and immaterial to its financial results. In addition, should the Company determine that any of its tax positions are uncertain it may record related interest and penalties that may be assessed. Interest recorded, if any, will be charged to interest expense, and penalties recorded will be charged to other expense in the Company’s statement of operations.

(f)	Investments
	Investments in affiliated companies with a 20% to 50% ownership interest are accounted for under the equity method and, accordingly, net income includes the Company’s proportionate share of their income or loss. In addition, the Company has an investment in a joint venture which is accounted for by the equity method because the Company does not have effective control or voting interest although the Company owns approximately 76 1/2% of the joint venture economic interest.
(g)	Stock-Based Compensation
	Parallel accounts for its stock based compensation using the prospective method under Statement of Financial Accounting Standards No. 123 (“SFAS 123”). Under this method, the fair values of all options granted since 2003 have been reflected as compensation expense over the periods in which the services are rendered.
	Parallel adopted SFAS 123(R) effective January 1, 2006, applying the modified prospective method, whereby compensation cost associated with the unvested portion of awards granted during the period of June 2001 to December 2002 were recognized over the remaining vesting period. Under this method, prior periods were not revised for comparative purposes. No options that were granted prior to June 2001 remained unvested at January 1, 2006.
(h)	Environmental Expenditures
	The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed.
	Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable.
(i)	Earnings Per Share
	Basic earnings per share excludes any dilutive effects of options, warrants and convertible securities and is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed similar to basic earnings per share; however, diluted earnings per share reflect the assumed conversion of all potentially dilutive securities.

F-10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     The following table provides the computation of basic and diluted earnings per share for the year ended December 31:

	2007			2006		2005
	($ in thousands, except per share data)
Basic EPS Comp utation:
Numerator—
Net income (loss)	$	(4,661	)	$	26,155	$	(1,589	)
Preferred stock dividend		—			—		(271	)
Net income (loss) available to common stockholders		(4,661	)		26,155		(1,860	)
Denominator—
Weighted average common shares outstanding		38,120			35,888		32,253
Basic earnings (loss) p er share	$	(0.12	)	$	0.73	$	(0.06	)
Diluted EPS Comp utation:
Numerator—
Net income (loss)	$	(4,661	)	$	26,155	$	(1,589	)
Preferred stock dividend		—			—		(271	)
Net income (loss) available to common stockholders	$	(4,661	)	$	26,155	$	(1,860	)
Denominator —
Weighted average common shares outstanding		38,120			35,888		32,253
Employee stock options		—			599		—
Warrants		—			269		—
Weighted average common shares for diluted earnings per share assuming conversion		38,120			36,756		32,253
Diluted earnings (loss) p er share	$	(0.12	)	$	0.71	$	(0.06	)

For the year ended December 31, 2007, the effects of all potentially dilutive securities (including options and warrants) were excluded from the computation of diluted earnings per share because the Company had a net loss and, therefore, the effect would have been anti-dilutive. Approximately 878,000 options and warrants were excluded from the computation of diluted earnings per share in 2007. For the year ended December 31, 2005, the effects of all potentially dilutive securities (including options, warrants and the “if converted” effects of convertible preferred stock) were excluded from the computation of diluted earnings per share because the Company had a net loss and, therefore, the effect would have been antidilutive. Approximately 1.7 million options, warrants and the “if converted” effects of convertible preferred stock were excluded from the computation of diluted earnings per share in 2005.

(j)	Use of Estimates in the Preparation of Consolidated Financial Statements
	Preparation of the accompanying Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. The oil and natural gas reserve estimates, and the related future net cash flows derived from those reserves, are used in the determination of depletion expense and the full-cost ceiling test and are inherently imprecise. Actual results could differ from those estimates.
(k)	Cash Equivalents
	For purposes of the statements of cash flows, the Company considers all demand deposits, money market accounts and certificates of deposit purchased with an original maturity of three months or less to be cash equivalents.

F-11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(l)	Restricted Cash
	Restricted cash as of December 31, 2007, includes $50,000 placed in a certificate of deposit for a Letter of Credit with the State of New Mexico and $25,000 placed in a certificate of deposit to be held as a Statewide Bond provided under the New Mexico Surface Owners Protection Act for benefit of surface owners affected. Restricted cash as of December 31, 2006, includes $50,000 placed in a certificate of deposit for a Letter of Credit with the State of New Mexico and approximately $275,000 placed in a certificate of deposit for a drilling bond.
(m)	Reclassifications
	Certain reclassifications have been made to prior years amounts to conform with current year presentation.
(n)	Derivative Financial Instruments
	Derivative financial instruments, utilized to manage or reduce commodity price risk related to the Company’s production and interest rate risk related to the Company’s long-term debt, are accounted for under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and for Hedging Activities", and related interpretations and amendments. Under this Statement, derivatives are carried on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (“OCI”) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges are also recognized in other expense. If the derivative is not designated as a hedge, changes in the fair value are recognized in other expense.
(o)	Revenue Recognition
	Oil and natural gas revenues are recorded using the sales method, whereby the Company recognizes oil and natural gas revenue based on the amount of oil and natural gas sold to purchasers. For the period ended December 31, 2007, 2006 and 2005, the Company did not have any significant oil or natural gas imbalances. The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists; (ii) delivery has occurred or services have been rendered; (iii) the seller’s price to the buyer is fixed or determinable; and, (iv) collectibility is reasonably assured.
	The following summarizes revenue for each of the three years ended December 31 by product sold.

	2007		2006			2005
			($ in thousands)
Oil revenue	$	69,315	$	68,076		$	47,800
Effects of oil hedges		—		(11,512	)		(12,139	)
Natural gas revenue		46,716		40,461			30,690
Effects of natural gas hedges		—		—			(201	)
	$	116,031	$	97,025		$	66,150

(p)	Recent Accounting Pronouncements
	In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“FAS 157”). FAS 157 defines fair value as used in numerous accounting pronounce-

F-12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ments, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosure requirements related to the use of fair value measures in financial statements. FAS 157 will be effective for the Company’s financial statements for the fiscal year beginning January 1, 2008; however, earlier application is encouraged. The Company is currently evaluating the impact that adoption might have on its financial position or results of operations, although the Company does not expect any impact to be significant.

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of FASB Statement No. 115,” (“FAS 159”) which will become effective on January 1, 2008. FAS 159 permits entities to measure eligible financial assets, financial liabilities and firm commitments at fair value, on an instrument-by-instrument basis, that are otherwise not permitted to be accounted for at fair value under other generally accepted accounting principles. The fair value measurement election is irrevocable and subsequent changes in fair value must be recorded in earnings. The Company will adopt this statement in the first quarter of 2008 and the Company does not expect to elect the fair value option for any eligible financial instruments and other items.

In April 2007, the FASB issued FASB Staff Position FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”). FSP FIN 39-1 clarifies that a reporting entity that is party to a master netting arrangement can offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement. FSP FIN 39-1 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Adoption of FSP FIN 39-1 is not expected to have a material impact on the Company’s consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non- controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008, which will be the company’s fiscal year 2009. The impact, if any, will depend on the nature and size of business combinations the Company consummates after the effective date.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008, which will be the company’s fiscal year 2009. Based upon the December 1, 2007 balance sheet, the statement would have no impact.

(2)	Fair Value of Financial Instruments
	The carrying amount of cash, accounts receivable, accounts payable, and accrued liabilities approximates fair value because of the short maturity of these instruments.
	The carrying amount of long-term debt outstanding under the Company's revolving credit facility in 2007 and 2006 and its term loan in 2006 approximated fair value because the Company’s borrowing rate on these financial instruments is based on a variable market rate of interest.

F-13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The carrying value of the Company’s 10.25% senior notes at December 31, 2007 is approximately $145.4 million and their estimated fair value is approximately $150.0 million. Fair value is estimated based on market trades at or near December 31, 2007.

The Company also has derivative instruments which are described in Footnote 6.

(3)	Oil and Natural Gas Properties
	The following table reflects capitalized costs related to the oil and natural gas properties as of December 31:

	2007			2006
	($ in thousands)
Proved properties	$	562,174		$	451,030
Unproved properties, not subject to depletion		86,402			50,375
		648,576			501,405
Accumulated depletion		(143,264	)		(113,467	)
	$	505,312		$	387,938

The following table reflects, by category of cost, amounts excluded from the depletion base as of December 31, 2007:

					Prepaid
					Drilling
					Costs and
	Leasehold		Geological and		Work-in-
Year Incurred	Costs		Geophysical		Progress		Total
	($ in thousands)
2007	$	34,558	$	2,105	$	8,942	$	45,605
2006		26,314		2,942		—		29,256
2005		6,256		675		—		6,931
Prior		3,575		1,035		—		4,610
	$	70,703	$	6,757	$	8,942	$	86,402

At December 31, 2007 and 2006, unevaluated costs of approximately $86.4 million and $50.4 million were excluded from the depletion base. These costs consist primarily of acreage acquisition, related geological and geophysical costs, prepaid drilling costs and work-in-progress. The majority of these costs relate to the Company’s New Mexico, Utah and Barnett Shale leasehold positions. The Company transfers these costs to the full cost pool as wells are drilled or as proven well locations are identified. The timing of these transfers is highly dependent on the Company’s future drilling program.

Certain directly identifiable internal costs of property acquisition, exploration, and development activities are capitalized. Such costs capitalized in 2007, 2006 and 2005 totaled approximately $1.9 million, $2.3 million and $1.5 million, respectively, including $394,000, $620,000 and $180,000 of capitalized interest for the year ended December 31, 2007, 2006 and 2005, respectively.

Depletion per equivalent unit of production (BOE) was $13.02, $10.88 and $7.61 for 2007, 2006 and 2005, respectively.

F-14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table reflects costs incurred in oil and natural gas property acquisition, exploration, and development activities for each of the years in the three year period ended December 31:

	2007		2006		2005
	($ in thousands)
Proved property acquisition costs	$	—	$	27,370	$	23,763
Unproved property acquisitions costs		36,750		30,058		11,743
Exploration costs		55,827		71,003		15,455
Development costs		61,766		69,285		26,640
	$	154,343	$	197,716	$	77,601

In November 2005, Parallel purchased producing and undeveloped oil and natural gas properties in the Harris San Andres Field located in Andrews and Gaines counties, Texas. The net purchase price was approximately $20.8 million. In January, 2006, Parallel acquired additional interest in these properties for a net purchase price of approximately $23.4 million, including adjustments. The 2006 purchase was made utilizing Parallel’s restricted cash and revolving credit facility.

In March 2006, Parallel purchased additional interests in the Barnett Shale Gas Project located in Tarrant County, Texas. The additional interests were acquired from five unaffiliated parties for a total cash purchase price of approximately $5.5 million. In April 2006, Parallel acquired an additional interest in the Barnett Shale Gas Project located in Tarrant County, Texas from one other unaffiliated third party for approximately $570,000.

The following table presents unaudited, pro forma operating results as if these property purchases had been made at the beginning of each period shown. The pro forma results have been prepared for comparative purposes only. They are not intended to represent what actual results would have been if the acquisitions had been made on those dates and these pro forma amounts are not indicative of future results.

	Twelve Months Ended
	December 31,
	Pro Forma		Pro Forma
	2006		2005
	($ in thousands)
Oil and gas revenue	$	97,500	$	74,270
Operating income	$	40,738	$	38,800
Net income available to common stockholders	$	26,291	$	(732	)
Net income per common share:
Basic	$	0.73	$	(0.02	)
Diluted	$	0.72	$	(0.02	)

F-15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(4)	Other Assets
	Below are the components of other assets as of December 31, 2007 and 2006:

	December 31,
	2007		2006
	($ in thousands)
Bank fees, net of accumulated amortization	$	1,185	$	1,361
Prepaid drilling		—		54
Fair value of derivative contracts		—		3,845
Deferred debt offering costs		1,575		—
Other		8		8
	$	2,768	$	5,268

(5)	Asset Retirement Obligation
	On January 1, 2003, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations". SFAS 143 requires companies to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and to capitalize an equal amount as part of the cost of the related oil and natural gas properties.
	The following table summarizes the Company's asset retirement obligation transactions for the years ended December 31:

	2007			2006			2005
	($ in thousands)
Beginning asset retirement obligation	$	5,063		$	2,495		$	2,132
Additions related to new properties		257			406			370
Revisions in estimated cash flows		(342	)		1,979			(3	)
Deletions related to property disposals		(365	)		(65	)		(116	)
Accretion expense		324			248			112
Ending asset retirement obligation	$	4,937		$	5,063		$	2,495

Accretion expense is recognized as a component of lease operating expense.

(6)	Derivative Instruments
	The Company enters into derivative contracts to provide a measure of stability in the cash flows associated with the Company’s oil and natural gas production and interest rate payments and to manage exposure to commodity price and interest rate risk. The Company’s objective is to lock in a range of oil and natural gas prices and to limit variability in its cash interest payments. In addition, the Company’s revolving credit facility requires the Company to maintain derivative financial instruments which limit the Company’s exposure to fluctuating commodity prices covering at least 50% of the Company’s estimated monthly production of oil and natural gas extending 24 months into the future.
	The Company designated all of its interest rate swaps, commodity collars and commodity swaps entered into in 2002 and 2003 as cash flow hedges (“hedges”). The effective portion of the unrealized gain or loss on cash flow hedges is recorded in other comprehensive income (loss) until the forecasted transaction occurs. During the term of a cash flow hedge, the effective portion of the change in the fair value of the derivatives is recorded in stockholders’ equity as other comprehensive income (loss) and then transferred to oil and natural gas revenues when the production is sold and interest expense as the interest accrues. Ineffective portions of

F-16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

hedges (changes in fair value resulting from changes in realized prices that do not match the changes in the hedge or reference price) are recognized in other expense as they occur.

As of December 31, 2005, the Company had recorded unrealized losses of $9.8 million, respectively, related to its derivative instruments designated as hedges, which represented the estimated aggregate fair values of the Company’s open hedge contracts as of that date. All derivative instruments previously designated as cash flow hedges had been settled prior to December 31, 2006.

Derivative contracts not designated as hedges are “marked to market” at each period end and the increases or decreases in fair values are recorded to earnings. No derivative instruments entered into subsequent to June 30, 2004 have been designated as cash flow hedges.

The Company is exposed to credit risk in the event of nonperformance by the counterparties to these contracts, BNP Paribas and Citibank, N.A. The Company periodically assesses their credit worthiness to mitigate this credit risk.

Interest Rate Sensitivity

Under the Company’s revolving credit facility, the Company may elect an interest rate based upon the agent bank’s base lending rate or the LIBOR rate, plus a margin ranging from 2.00% to 2.50% per annum, depending on the Company’s borrowing base usage. The interest rate the Company is required to pay, including the applicable margin, may never be less than 5.00%. Under the Company’s second lien term loan facility, the Company had the option to elect an interest rate based upon an alternate base rate, or the LIBOR rate, plus a margin of 4.50%.

Interest Rate Swaps. The Company has entered into interest rate swaps with BNP Paribas and Citibank, N.A. (the “counterparties”) which are intended to have the effect of converting the variable rate interest payments to be made on the Company’s revolving credit agreement to fixed interest rates for the periods covered by the swaps. Under terms of these swap contracts, in periods during which the fixed interest rate stated in the swap contract exceeds the variable rate (which is based on the 90 day LIBOR rate), the Company pays to the counterparties an amount determined by applying this excess fixed rate to the notional amount of the contract. In periods when the variable rate exceeds the fixed rate stated in the swap contracts, the counterparties pay an amount to the Company determined by applying the excess of the variable rate over the stated fixed rate to the notional amount of the contract.

The Company completed a fixed interest rate swap contract with BNP Paribas, based on the 90-day LIBOR rates at the time of the contract. This interest rate swap was treated as a cash flow hedge as defined by SFAS 133. This interest rate swap was on $10.0 million of the Company's variable rate debt for all of 2006. As of December 31, 2006, this contract had expired.

The Company has historically employed interest rate swap contracts with BNP Paribas and Citibank, N.A. exchanging 90-day LIBOR rates for a fixed interest rate. These contracts are accounted for by “mark to market” accounting as prescribed in SFAS 133. The Company has historically viewed these contracts as additional protection against future interest rate volatility. As a result of the issuance of senior notes and common stock in 2007, the Company's indebtedness under the Revolving Credit Facility has been reduced below the nominal amounts currently covered by these swap contracts. Under a covenant contained in the Company's Revolving Credit Facility, these swap contracts for nominal amounts in excess of the Company's outstanding floating rate indebtedness are considered speculative and are, therefore, not allowed. This covenant has been waived by the Company's lenders through the end of 2008.

F-17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below recaps the nature of these interest rate swaps and the fair market value of these contracts as of December 31, 2007.

						Estimated
	Notional		Weighted Average			Fair Market Value
Period of Time	Amounts		Fixed Interest Rates			at December 31, 2007
	($ in millions)					($ in thousands)
January 1, 2008 thru December 31, 2008	$	100		4.86	%	$	(800	)
January 1, 2009 thru December 31, 2009	$	50		5.06	%		(754	)
January 1, 2010 thru October 31, 2010	$	50		5.15	%		(441	)
Total Fair Market Value						$	(1,995	)

Commodity Price Sensitivity

Collars. Collars are contracts which combine both a put option or “floor” and a call option or “ceiling”. These contracts may or may not involve payment or receipt of cash at inception, depending on “ceiling” and “floor” pricing.

A summary of the Company’s collar positions at December 31, 2007 is as follows:

							Estimated
	Barrles of		NYMEX Oil Prices				Fair Market
Period of Time	Oil		Floor		Cap		Value
							($ in thousands)
January 1, 2008 thru December 31, 2008		347,700	$	63.42	$	83.86	$	(4,003	)
January 1, 2009 thru December 31, 2009		620,500	$	63.53	$	80.21		(6,846	)
January 1, 2010 thru October 31, 2010		486,400	$	63.44	$	78.26		(5,153	)
	M M Btu of		WAHA Gas Prices
	Natural Gas		Floor		Cap
January 1, 2008 thru M arch 31, 2008		546,000	$	6.50	$	9.50		87
April 1, 2008 thru December 31, 2008		1,375,000	$	6.75	$	8.40		63
Total Fair M arket Value							$	(15,852	)

Commodity Swaps. Generally, swaps are an agreement to buy or sell a specified commodity for delivery in the future, at an agreed fixed price. Swap transactions convert a floating or market price into a fixed price. For any particular swap transaction, the counterparty is required to make a payment to the Company if the reference price for any settlement period is less than the swap or fixed price for such contract, and the Company is required to make a payment to the counterparty if the reference price for any settlement period is greater than the swap or fixed price for such contract.

F-18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company has entered into oil and natural gas swap contracts with BNP Paribas. A recap for the period of time, number of barrels, and weighted average swap prices are as follows:

					Estimated
	Barrels of		NYMEX Oil		Fair Market
Period of Time	Oil		Swap Price		Value
					($ in thousands)
January 1, 2008 thru December 31, 2008		439,200	$	33.37	$	(25,621	)

(7)	Equity Investment and Property Acquisitions
	Prior to 2006, the Company had three separate partnership investments to construct pipeline systems which gather natural gas, primarily on its leaseholds in the Barnett Shale area. The partnership investments included West Fork Pipeline Company I, L.P., West Fork Pipeline Company II, L.P. and West Fork Pipeline Company V, L.P. These investments were recorded as equity method investments in the accompanying consolidated balance sheet.
	In the fourth quarter of 2006, substantially all of the assets of West Fork Pipeline I and West Fork Pipeline V were sold. The Company received distributions of $16.0 million and $683,000, respectively, as a result of these asset sales. The total of these distributions, approximately $16.7 million, is reported in the accompanying statement of cash flows for 2006 in “Cash flows from operating activities” as “Return on investment in pipelines and gathering systems ventures” in the amount of $9.0 million, which represents the excess of distributions received over the Company's cash investments in these ventures, and in “Cash flows from investing activities” as “Return of investment in pipelines and gathering systems ventures” in the amount of $7.7 million, representing the return through distribution of the Company's previous cash investments in the two joint ventures.
	The Company has invested $328,000 in West Fork Pipeline II through 2007. West Fork Pipeline II is currently acquiring the necessary easements and permits to begin transmission of natural gas.
	The Company has invested $9.6 million in the Hagerman Gas Gathering System Joint Venture (“Hagerman”) to construct pipelines on certain of its leaseholds in New Mexico. In late September 2006, transmission of natural gas commenced through the first phase of the system. The Hagerman Gas Gathering System is currently being extended to additional productive areas. The Company anticipates additional investments in Hagerman during 2008.
	The Company’s investment percentage in each of these ventures was as follows:

West Fork Pipeline Company II, L.P.	23.25848	%
Hagerman Gas Gathering System	76.50000	%

The Company’s investment in Hagerman is accounted for by the equity method because the Company does not have voting control. All significant actions taken by Hagerman must be approved by the Company plus one of the two other equity owners. Consequently, the remaining equity owners can prevent voting control by the Company.

F-19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company’s equity investments for the periods indicated consisted of the following:

	December 31,
	2007		2006
	($ in thousands)
West Fork Pipeline Company II, L.P.	$	312	$	280
Hagerman Gas Gathering System		8,326		6,174
	$	8,638	$	6,454

The Company’s earnings from equity investments for the periods indicated were as follows:

	Year Ended December 31,
	2007			2006			2005
	($ in thousands)
West Fork Pipeline Company I, L.P.(1)	$	161		$	9,286		$	(83	)
West Fork Pipeline Company II, L.P.		3			(50	)		(5	)
West Fork Pipeline Company V, L.P.(2)		126			(147	)		(1	)
Hagerman Gas Gathering System		(601	)		(496	)		—
	$	(311	)	$	8,593		$	(89	)

(1)	Included in the Company’s earnings for 2007 is its proportionate share of a final cash disbursement of $161,000 received in the fourth quarter of 2007. Included in the Company’s earnings for 2006 is its proportionate gain in the sale of the partnership assets of approximately $9.1 million.
(2)	Included in the Company’s earnings for 2007 is its proportionate share of a final cash disbursement of $126,000 received in the fourth quarter of 2007. Included in the Company’s earnings for 2006 is its proportionate loss in the sale of the partnership assets of approximately $90,000.

Summarized combined financial information for the Company's equity investments (listed above) is reported below. Amounts represent 100% of the investees’ financial information:

	December 31,
	2007		2006
	($ in thousands)
Balance Sheet
Current assets	$	62	$	94
Account receivables — affiliates		696		1,314
Total current assets		758		1,408
Plan and pipeline costs		10,917		8,351
Total assets	$	11,675	$	9,759
Current liabilities	$	50	$	15
Accounts payable — affiliates		523		1,314
Total current liabilities		573		1,329
Partner capital		11,102		8,430
Owners’ equity	$	11,675	$	9,759

F-20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year Ended December 31,
	2007			2006			2005
	($ in thousands)
Income Statement
Revenues	$	847		$	2,402		$	627
Costs and expenses		(1,654	)		(2,597	)		(699	)
Gain/loss on sale of assets		782			23,780			—
Net income (loss)	$	(25	)	$	23,585		$	(72	)

	As of December 31, 2007 and 2006, Hagerman had accounts receivable due from joint venturers of approximately $0.5 million and $1.3 million, respectively, for operating and pipeline construction related capital contributions. Parallel advanced funds in these amounts to Hagerman to meet capital needs until payment on account is received from the other joint venturers.
(8)	Credit Arrangements
	In the past, the Company maintained two separate credit facilities. The Company’s Third Amended and Restated Credit Agreement (or the “Revolving Credit Agreement”), dated as of December 23, 2005, with a group of bank lenders provides a revolving line of credit having a “borrowing base limitation” of $200.0 million at December 31, 2007. The total amount that the Company can borrow and have outstanding at any one time is limited to the lesser of $350.0 million or the borrowing base established by the lenders. At December 31, 2007, the principal amount outstanding under the Company’s revolving credit facility was $60.0 million, and $445,000 was reserved for the Company’s letters of credit. The second credit facility (or the “Second Lien Agreement”) was a five year term loan facility provided to the Company under a Second Lien Term Loan Agreement, dated November 15, 2005, with a group of banks and other lenders. The Second Lien Term Loan Agreement was paid off and terminated on July 31, 2007, with the Company’s payment to the lenders of $50.2 million, including interest. This payment was made with proceeds from the Company’s sale of unsecured senior notes, or “senior notes”.
	On July 31, 2007, the Company completed a private offering of unsecured senior notes in the principal amount of $150.0 million.
	The credit facilities have varying interest rates and consist of the following bank’s base rate and LIBOR tranches at December 31:

	2007		2006
	($ in thousands)
Revolving Credit Facility note payable to banks,
Agent bank’s base lending rate of 8.25%	$	—	$	2,000
Libor Tranche at 6.84% and 7.61%		60,000		113,000
Second Lien Term Loan payable to banks,
Libor Tranche at 9.875%		—		50,000
Senior notes (principal amount $150,000 in 2007) rate of 10.25%		145,383		—
Total notes payable to banks	$	205,383	$	165,000

Revolving Credit Facility

The Revolving Credit Agreement provides for a credit facility that allows the Company to borrow, repay and reborrow amounts available under the revolving credit facility. The amount of the borrowing base is based

F-21

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

primarily upon the estimated value of the Company’s oil and natural gas reserves. The borrowing base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each year or at other times required by the lenders or at the Company’s request. If, as a result of the lenders’ redetermination of the borrowing base, the outstanding principal amount of the Company’s loan exceeds the borrowing base, it must either provide additional collateral to the lenders or repay the principal of the revolving credit facility in an amount equal to the excess. Except for the principal payments that may be required because of the Company’s outstanding loans being in excess of the borrowing base, interest only is payable monthly.

Loans made to the Company under this revolving credit facility bear interest at the bank’s base rate or the LIBOR rate, at the Company’s election. Generally, the bank’s base rate is equal to the “prime rate” published in the Wall Street Journal.

The LIBOR rate is generally equal to the sum of (a) the rate designated as “British Bankers Association Interest Settlement Rates” and offered on one, two, three, six or twelve month interest periods for deposits of $1.0 million, and (b) a margin ranging from 2.00% to 2.50%, depending upon the outstanding principal amount of the loans. If the principal amount outstanding is equal to or greater than 75% of the borrowing base, the margin is 2.50%. If the principal amount outstanding is equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.25%. If the principal amount outstanding is less than 50% of the borrowing base, the margin is 2.00%.

The interest rate the Company is required to pay on its borrowings, including the applicable margin, may never be less than 5.00%. At December 31, 2007, the Company’s Libor interest rate, plus margin, was 6.84% on $60.0 million.

In the case of base rate loans, interest is payable on the last day of each month. In the case of LIBOR loans, interest is payable on the last day of each applicable interest period.

If the total outstanding borrowings under the revolving credit facility are less than the borrowing base, an unused commitment fee is required to be paid to the lenders. The amount of the fee is .25% of the daily average of the unadvanced amount of the borrowing base. The fee is payable quarterly.

If the borrowing base is increased, the Company is required to pay a fee of .375% on the amount of any increase in the borrowing base.

The Revolving Credit Agreement contains various restrictive covenants, including (i) maintenance of a minimum current ratio, (ii) maintenance of a maximum ratio of funded indebtedness to earnings before interest, income taxes, depreciation, depletion and amortization, (iii) maintenance of a minimum net worth, (iv) prohibition of payment of dividends and (v) restrictions on incurrence of additional debt. The Company has pledged substantially all of its producing oil and natural gas properties to secure the repayment of its indebtedness under the Revolving Credit Agreement.

As of December 31, 2007 the Company was in compliance with all of the covenants in its Revolving Credit Agreement.

All outstanding principal under the revolving credit facility is due and payable on October 31, 2010. The maturity date of the Company’s outstanding loans may be accelerated by the lenders upon the occurrence of an event of default under the Revolving Credit Agreement.

Second Lien Term Loan Facility

Until July 31, 2007, the Second Lien Agreement provided a $50.0 million term loan to the Company. Loans made to the Company under this credit facility bore interest at an alternate base rate or the LIBO rate, at the Company’s election. The alternate base rate was the greater of (a) the prime rate in effect on such day and (b) the “Federal Funds Effective Rate” in effect on such day plus ¹/2 of 1%, plus a margin of 3.50% per annum.

The LIBO rate was generally equal to the sum of (a) a designated rate appearing in the Dow Jones Market Service for the applicable interest periods offered in one, two, three or six month periods and (b) an applicable margin rate per annum equal to 4.50%.

F-22

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In the case of alternate base rate loans, interest was payable the last day of each March, June, September and December. In the case of LIBO loans, interest was payable the last day of the tranche period not to exceed a three month period.

Upon completion of the Company’s senior notes offering, the Company paid off and terminated this facility with $50.2 million of the net proceeds from the offering. As a result the Company charged to earnings $760,000 of previously capitalized debt issuance costs.

Senior Notes

On July 31, 2007, the Company completed a private offering of unsecured senior notes (the “senior notes”) in the principal amount of $150.0 million. The senior notes mature on August 1, 2014 and bear interest at 10.25% which is payable semi-annually beginning on February 1, 2008. Prior to August 1, 2010, the Company may redeem up to 35% of the senior notes for a price equal to 110.250% of the original principal amount of the senior notes with the proceeds of certain equity offerings. On or after August 1, 2011 the Company may redeem all or some of the senior notes at a redemption price that will decrease from 105.125% of the principal amount of the senior notes to 100% of the principal amount on August 1, 2013. In addition, prior to August 1, 2011, the Company may redeem some or all of the senior notes at a redemption price equal to 100% of the principal amount of the senior notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. Generally, the “make-whole” premium is an amount equal to the greater of (a) 1% of the principal amount of the senior notes being redeemed and (b) the excess of the present value of the redemption price of such notes as of August 1, 2011 plus all required interest payments due through August 1, 2011 (computed at a discount rate equal to a specified U.S. “Treasury Rate” plus 50 basis points), over the principal amount of the senior notes being redeemed.

The indenture governing the senior notes restricts the Company’s ability to: (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the senior notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business.

The Company agreed, pursuant to a Registration Rights Agreement with the initial purchasers of the senior notes, to use its commercially reasonable efforts to prepare and file with the Securities and Exchange Commission, within 180 days after July 31, 2007, a registration statement with respect to a registered offer to exchange freely tradable notes having substantially identical terms as the senior notes and to use its reasonable best efforts to cause the registration statement to be declared effective within 210 days after July 31, 2007. The registration statement became effective on January 29, 2008. If the Company fails to meet certain other obligations under the Registration Rights Agreement, the Company may be required to pay additional interest to holders of the senior notes. The rate of additional interest will be .25% per year for the first 90-day period immediately following a determination that the provisions of the Registration Rights Agreement have not been fulfilled, with the rate increasing by an additional .25% for each subsequent 90 day period up to a maximum additional interest rate of 1.0% per year. Under this agreement, the maximum additional interest that the Company could be required to pay over the life of the senior notes is approximately $9.4 million.

F-23

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(9)	Income Taxes
	The Company’s income tax provision (benefit) consists of the following:

	Years ended December 31,
	2007			2006		2005
	($ in thousands)
Deferred income tax (benefit) expense	$	(4,215	)	$	13,894	$	(1,676	)
Deferred tax benefits of stock option exercises credited to additional paid in capital		816			—		—
Deferred income tax (benefit) expense related to loss/gain on derivatives in other comprehensive loss		—			3,318		515
Current state tax		80			—		—
Total income tax provision (benefit)	$	(3,319	)	$	17,212	$	(1,161	)

Income tax (benefit) expense differs from the amount computed at the federal statutory rate as follows:

	Year ended December 31,
	2007			2006		2005
	($ in thousands)
Income tax (benefit) expense at statutory rate	$	(2,712	)	$	13,617	$	(1,110	)
Statutory depletion		(185	)		37		(443	)
State tax benefit, net of federal tax effect		(592	)		101		16
Nondeductible expenses and other		170			139		(139	)
Income tax (benefit) expense	$	(3,319	)	$	13,894	$	(1,676	)

Prior to 2007, the Company had not recognized the tax benefits of state net operating loss carryovers due to uncertainty about their ultimate realization. The Texas Margin Tax, a revision of Texas state tax laws, applied to earnings for the first time in 2007. In June 2007, the state of Texas enacted changes to the Texas Margin Tax legislation originally enacted in 2006, and issued final rules related to that legislation in December 2007. The utilization of a credit for prior taxable losses contained in this legislation is dependent on an election to be made by the taxpayer. Based on the Company’s tax planning strategies and the determination (made in December 2007) that the election to utilize the credit would be beneficial to the Company’s state and federal tax positions, the Company decided to make the appropriate election by May 2008, as required. As a result, the Company has recorded a net state tax benefit of $592,000. This net state benefit is composed of (i) current tax expense of $80,000, (ii) deferred tax expense of $984,000 associated with changes in the state tax rate, (iii) $156,000 of state tax benefit related to changes in deferred state tax liabilities, (iv) benefit from the recognition of business loss credits of approximately $1.8 million, and (v) $305,000 of federal tax expense associated with the net state tax benefit.

F-24

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liability at December 31 are as follows:

	2007			2006
	($ in thousands)
Current:
Deferred tax assets:
Fair market value losses on derivatives expected to be settled within one year	$	10,293		$	4,340
Noncurrent:
Deferred tax assets:
Federal operating loss carryforwards	$	15,081		$	16,942
State operating loss credit carryforwards		1,805			—
Statutory depletion carryforwards		2,609			2,424
Alternative minimum tax credit carryforwards		157			157
Fair market value losses on derivatives not expected to be settled within one year		5,275			4,102
Asset retirement obligations		350			233
Other		73			26
Total noncurrent deferred tax assets		25,350			23,884
Deferred tax liabilities:
Property and equipment, principally due to differences in basis, expensing of intangible drilling costs for tax purposes and depletion		(50,368	)		(48,019	)
Federal impact of state operating loss credit carryforwards		(614	)		—
Partnership investments		(413	)		(172	)
Total deferred tax liabilities		(51,395	)		(48,191	)
Net noncurrent deferred income tax liability	$	(26,045	)	$	(24,307	)

As of December 31, 2007, the Company had net operating loss carry forwards for regular tax and alternative minimum taxable income (AMT) purposes available to reduce future taxable income. These carry forwards expire as follows:

	Net operating		AMT
	loss		operating loss
	($ in thousands)
2019	$	2,566	$	2,918
2021		4,576		4,498
2022		44		44
2023		8		332
2024		3,718		3,806
2025		6,258		5,008
2027		27,187		25,015
	$	44,357	$	41,621

The Company continually assesses its ability to use all of its federal net operating loss carryforwards and state operating loss credit carryforwards that result from substantial income tax deductions and prior year losses. The Company considers future federal and state taxable income in making such assessments. If the Company concludes that it is more likely than not that some portion or all of the deferred tax assets will not

F-25

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

be realized under accounting standards, they will be reduced by a valuation allowance. The Company believes that it is more likely than not that it will utilize all of these federal net operating loss carryforwards and state operating loss credit carryforwards in connection with federal and state income tax generated in the future.

	As of December 31, 2007, the Company had approximately $157,000 of AMT credit carryforwards that have no expiration date.
(10)	Equity Transactions
	Sale of Equity Securities
	On August 16, 2006, the Company sold 2,500,000 shares of its common stock, $.01 par value per share, pursuant to a public offering at a price of $25.25 per share. Gross cash proceeds were $63.1 million, and net proceeds were approximately $60.3 million. The proceeds were used for general corporate purposes, including debt repayment and the acceleration of Parallel’s drilling and completion operations in certain core areas such as the Barnett Shale natural gas, New Mexico Wolfcamp natural gas and Permian Basin west Texas oil properties.
	On December 6, 2007, the Company sold 3,000,000 shares of its common stock in an underwritten public offering at a price of $18.50. The Company used the net proceeds for general corporate purposes and for conducting exploitation, development and acquisition activities in certain core areas such as the Company’s Permian Basin properties and its Barnett Shale gas project.
(11)	Stock Compensation, Warrants and Rights
	The Company awards both incentive stock options and nonqualified stock options to selected key employees, officers, and directors. The options are awarded at an exercise price equal to the closing price of the Company’s common stock on the date of grant. These options vest over a period of two to ten years with a ten-year exercise period. As of December 31, 2007, options expire beginning in 2008 and extending through 2017.

(a)	Stock Options
	A summary of the Company’s employee stock options as of December 31, 2007, 2006 and 2005, and changes during the years ended on those dates is presented below:

	Year ended					Year ended					Year ended
	December 31, 2007					December 31, 2006					December 31, 2005
	Number of			Weighted		Number of			Weighted		Number of			Weighted
	shares			average price		shares			average price		shares			average price
	(in thousands)					(in thousands)					(in thousands)
Stock options:
Outstanding at beginning of year		1,199		$	5.40		1,405		$	5.22		1,919		$	3.71
Options granted		18			22.89		—			—		200			12.27
Options exercised		(619	)		3.98		(176	)		4.35		(714	)		3.15
Options cancelled		—			—		(30	)		3.09		—			—
Options forfeited		(40	)		12.27		—			—		—			—
Outstanding at end of year		558		$	7.03		1,199		$	5.40		1,405		$	5.22
Exercisable at end of year		420		$	5.39		1,001		$	4.32		1,160		$	4.01
Weighted average fair value of options granted during the year				$	12.45				$	—				$	7.11

F-26

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about the Company’s employee stock options outstanding and exercisable at December 31, 2007:

	Average		Intrinsic
	Remaining Life		Value
			(in thousands)
Stock options outstanding as of December 31, 2007		5.1	$	5,909
Currently exercisable as of December 31, 2007		4.4	$	5,139

For the twelve months ended December 31, 2007, 2006 and 2005, Parallel recognized compensation expense of approximately $247,000, $531,000 and $278,000 with tax benefits of approximately $84,000, $181,000 and $95,000, respectively, associated with its stock option grants.

The following table presents the future stock-based compensation expense expected to be recognized over the vesting period:

	($ in thousands)
2008	$	228
2009		93
2010		29
Total	$	350

Nonvested options were 137,500 at December 31, 2007. During the twelve months ended December 31, 2007, 618,500 options were exercised, options to purchase 17,500 shares of common stock were granted to one individual, options to purchase 40,000 shares were forfeited and no options expired. During 2006 the Company settled 30,000 options for approximately $511,000.

The fair value of each option award is estimated on the date of grant. The fair value of stock options granted prior to and remaining outstanding at December 31, 2007 and that had option shares subject to future vesting at that date was determined using the Black-Scholes option valuation method and the assumptions noted in the following table. Expected volatilities are based on historical volatility of the common stock. The expected term of the options granted used in the model represent the period of time that options granted are expected to be outstanding.

	2007			2005			2001
Expected volatility		52.52	%		54.20	%		57.95	%
Expected dividends		0.00			0.00			0.00
Expected term (in years)		6			7			8
Risk free rate		4.89	%		4.20	%		5.05	%

F-27

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	($ in thousands)
Intrinsic Value of Options Exercised Twelve Months Ended December 31, 2007	$	10,071
Intrinsic Value of Options Exercised Twelve Months Ended December 31, 2006	$	2,855
Intrinsic Value of Options Exercised Twelve Months Ended December 31, 2005	$	9,169
Fair Market Value of Options Granted Twelve Months Ended December 31, 2007	$	218
Fair Market Value of Options Granted Twelve Months Ended December 31, 2006	$	—
Fair Market Value of Options Granted Twelve Months Ended December 31, 2005	$	1,423

	There were 17,500 stock options granted for the twelve months ended December 31, 2007 with a fair market value of $218,000. For the twelve months ended December 31, 2005 there were 200,000 options granted with a fair market value of $1.4 million.
(b)	Stock Warrants
	The Company has 300,030 perpetual warrants outstanding at December 31, 2007, 2006, and 2005, which were issued as part of the Company’s initial public offering in 1980. Each warrant allows the holder to buy one share of common stock for $6.00. The warrants are exercisable for a 30 day period commencing on the date a registration statement covering exercise is declared effective. The warrants contain antidilution provisions.
	The Company also had an additional 136,708 warrants outstanding at December 31, 2005 issued as partial payment for services rendered for financial and investment advice in 2001. The warrants had a term of five years from date of issuance and a vesting period of one year. The warrants had an exercise price of $2.95 per share and contain a provision for cashless exercise. The expense related to these warrants in the amount of $99,000 was recorded in other expenses in 2001 based on the estimated fair value on the date of grant using the Black-Scholes option pricing model. As of December 31, 2006 these warrants had been fully exercised.
	The Company had 100,000 warrants outstanding at December 31, 2006, 2005 and 2004, which were issued as partial payment for services rendered for financial and investment advice for the Company’s private placement offering in December, 2003. The warrants had a term of five years from date of issuance and vesting period of one year. The warrants had an exercise price of $3.98 per share and contained a provision for cashless exercise. The fair value related to these warrants in the amount of $157,000 was recorded in other expenses in 2003 based on the estimated fair value on the date of grant using the Black-Scholes option pricing model. The holders of these warrants elected to exercise during 2007 through cashless exercise as allowed under the terms of the warrants. As a result, 82,734 common shares were issued to the warrant holders.
(c)	Stock Rights
	On October 5, 2000, the board of directors adopted a Stockholder Rights Plan (the “Plan”) and declared a dividend of one Stock Right for each outstanding share of the Company’s common stock. Generally, the Plan is designed to protect the Company from unfair or coercive takeover attempts, prevent a potential acquiror from gaining control of the Company without fairly compensating all of the Company’s stockholders, and encourage third parties that may have an interest in acquiring the Company to negotiate with the Company’s board of directors. In particular, the Plan is intended to (i) reduce the risk of coercive or partial tender offers that may not offer fair value to all stockholders; (ii) deter purchasers who through open market or private purchase may attempt to achieve a position of substantial influence or control over the Company without paying a fair control premium to selling or remaining stockholders; and (iii) preserve the board of directors’ bargaining power and flexibility to deal with acquirors and otherwise to seek to maximize value for all stockholders. The Plan is intended to achieve these goals by confronting a potential acquiror of the Company’s common stock with the possibility that the Company or its stock-

F-28

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	holders will be able to substantially dilute the acquiror’s equity interest by using the Stock Rights to acquire additional Company common stock, or in certain cases stock of the acquiror, at a 50% discount.
	If a person acquires 15% or more of the Company’s common stock or a tender offer or exchange offer is made for 15% or more of the common stock, each Stock Right will entitle the holder to purchase from the Company one one-thousandth of a share of Series A Preferred Stock, par value $0.10 per share, at an exercise price of $26.00 per one one-thousandth of a share, subject to adjustment.
	Initially, the Stock Rights attach to all common stock certificates representing shares then outstanding, and no separate Stock Rights certificates will be distributed. The Stock Rights separate from the common stock upon the earlier of (1) ten business days following a public announcement that a person or group of affiliated or associated persons has acquired or obtained the right to acquire, beneficial ownership of 15% or more of the outstanding shares of common stock or (2) ten business days (or such later date as the board of directors shall determine) following the commencement of a tender or exchange offer that would result in a person or group beneficially owning 15% or more of such outstanding shares of common stock. The date the Stock Rights separate is referred to as the “distribution date”.
	Under certain circumstances the Stock Rights entitle the holders to buy shares of the acquirer’s common stock at a 50% discount. In the event that, at any time after a person has acquired 15% or more of the Company’s common stock, (1) the Company enters into a merger or other business combination transaction in which the Company is not the surviving corporation; (2) the Company is the surviving corporation in a transaction in which all or part of the common stock is exchanged for cash, property or securities of any other person; or, (3) more than 50% of the assets, cash flow or earning power of the Company is sold, each right holder will have the option to buy for the purchase price stock of the acquiring company having a value equal to two times the purchase price of the Stock Right.
	The Stock Rights are not exercisable until the distribution date and will expire at the close of business on October 5, 2010, unless earlier redeemed by the Company for $0.001 per Stock Right.
	At issuance, the Stock Rights had no determinable value and, therefore, no accounting entry was required. The Stock Rights have not had, nor does the Company anticipate that the Stock Rights will have, an effect on its results of operations.
(d)	Non-Employee Director Stock Grant Plan
	Effective July 1, 2004, the Company began paying an annual retainer fee to each non-employee Director in the form of shares of the Company’s common stock. Under the 2004 Non-Employee Director Stock Grant Plan, each non-employee Director is entitled to receive an annual retainer fee in the form of shares of common stock having a value of $25,000. The shares of stock are automatically granted on the first day of July in each year. The actual number of shares received is determined by dividing $25,000 by the average daily closing price of the common stock on the Nasdaq Stock Market for the ten consecutive trading days commencing fifteen trading days before the first day of July of each year. On July 1, 2007 and in accordance with the terms of the plan, the Company issued a total of 4,400 shares of common stock to four non-employee Directors as follows: Jeffrey G. Shrader — 1,100 shares; Edward A. Nash — 1,100 shares; Martin B. Oring — 1,100 shares; and Ray M. Poage — 1,100 shares. On July 1, 2006 and in accordance with the terms of the plan, the Company issued a total of 4,696 shares of common stock to four non-employee Directors as follows: Jeffrey G. Shrader — 1,174 shares; Dewayne E. Chitwood — 1,174 shares; Martin B. Oring — 1,174 shares; and Ray M. Poage — 1,174 shares. On July 1, 2005, and in accordance with the terms of the plan, the Company issued a total of 11,596 shares of common stock to four non-employee Directors as follows: Jeffrey G. Shrader — 2,899 shares; Dewayne E. Chitwood — 2,899 shares; Martin B. Oring — 2,899 shares; and Ray M. Poage — 2,899 shares. The Company has 74,420 remaining shares of common stock available to issue to directors under this arrangement.

(12)	Related Party Transactions
	An entity owned by Thomas R. Cambridge, the Company’s former Chairman of the Board of Directors, is the owner and acted as the Company’s agent in performing the routine day to day operations on two wells. In 2007, 2006 and 2005 the Company was billed approximately $27,000, $23,000 and $20,000, respectively, for

F-29

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	the Company’s pro rata share of lease operating and drilling expenses and received approximately $65,000, $176,000 and $161,000 in 2007, 2006 and 2005 respectively, in oil and natural gas revenues related to these wells. These two wells were acquired in 1984.
	An entity, of which Mr. Cambridge is the President, owned interests in certain wells that are administered by the Company. During 2007 the Company charged approximately $1,300 for lease operating expenses and paid approximately $4,600 in oil and natural gas revenues related to these wells. In June 2007, these wells were sold by the entity and the Company to an unaffiliated third party and the Company distributed approximately $10,000 to the entity, its pro rata share of the sales proceeds.
	Dewayne E. Chitwood, a former Director of the Company, also serves as director of an entity which owned 110,000 shares of preferred stock of the Company. In addition, a Foundation, where Mr. Chitwood is the Chairman of the board of directors of the Foundation; and a Trust where he is Trustee, owned a total of 55,000 shares each of preferred stock of the Company. These shares of preferred stock of the Company were purchased in 1998 at a price of $10 per share on the same terms as all other unaffiliated purchasers. On June 6, 2005 the 110,000 and the 55,000 shares of preferred stock were converted to 314,285 and 157,142 shares of common stock, respectively.
	An entity, in which Mr. Chitwood is an officer of the managing general partner, owned interests in certain wells that are operated by the Company. During 2005 the Company charged approximately $4,000 for lease operating expenses and paid approximately $8,000 in oil and natural gas revenues related to these wells. In 2005 the Company paid to the entity approximately $140,000 in payment of net proceeds attributable to its pro rata share from the sale of the interests.
	In December, 2001, and prior to his employment with Parallel, Donald E. Tiffin, Parallel’s Chief Operating Officer, received a 3% working interest from an unaffiliated third party in the Diamond M Project in Scurry County, Texas for services rendered in connection with assembling the project. In August, 2002, shortly after his employment with Parallel, and due to the personal financial exposure in the Diamond M Project and to prevent the interest from being acquired by a third party, Mr. Tiffin assigned two-thirds of his ownership interest in the project to Parallel at no cost, leaving him with a 1% working interest. Parallel acquired its initial interest in the Diamond M Project in December, 2001. During 2007, the Company charged approximately $45,000 for capital expenditures and lease operating expenses and paid approximately $65,000 in oil and natural gas revenues related to this project. In addition, $5,000 and $8,000 of this balance was for outstanding joint interest billings to an executive officer as of December 31, 2007 and 2006. These receivables were collected within one month of billing.
	As of December 31, 2007 and 2006, the Company had accounts receivable of $4.0 million and $3.3 million, respectively, from affiliates. Joint interest receivables from a joint interest owner (who is also a joint venture partner in Hagerman) represented $3.4 million and $2.0 million of these balances at the December 31, 2007 and 2006, respectively.
	The remaining receivables from affiliates represent Parallel’s advance to Hagerman as described in Note 7.
(13)	Statements of Cash Flows
	In 2006, $40,000 was paid for estimated alternative minimum tax. No income taxes were paid in 2007 and 2005.
	The Company made interest payments of approximately $13.1 million, $12.5 million, and $5.4 million in 2007, 2006 and 2005, respectively.
	At December 31, 2007, 2006 and 2005, there were $11.0 million, $8.5 million and $2.5 million, respectively, of property additions accrued in accounts payable.

F-30

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(14)	Major Customers
	The following purchasers accounted for 10% or more of the Company’s oil and natural gas sales for the years ended December 31:

	2007			2006			2005
Allegro Investments, Inc.		(1	)		(1	)		14	%
Conoco, Inc.		21	%		20	%		12	%
Texland Petroleum, Inc.		30	%		30	%		40	%
Tri-C Resources, Inc.		(1	)		12	%		(1	)
Dale Op erating Company		(1	)		10	%		(1	)
Chesapeake Op erating, Inc.		12	%		(1	)		(1	)

⁽¹⁾ Less than 10%.

(15)	Commitments and Contingencies
	On May 21, 2007, the Company received a Notice of Proposed Adjustment, or the “Notice” from the Internal Revenue Service, or the “Service”, advising the Company of a proposed adjustment to its calculations of federal income tax resulting in a proposed alternative minimum tax liability in the aggregate amount of approximately $2.0 million for the years 2004 and 2005. After advising the Service that the Company intended to appeal the Notice, the Company received correspondence from the Service on July 10, 2007 stating that the issue remains in development pending receipt of additional documents requested and any proposed tax adjustment would not be made until after reviewing the documents requested. On November 5, 2007, the Company received an examination report related to this matter which reduces the amount of proposed adjustment to approximately $1.1 million, which includes interest. On December 21, 2007, the Company filed an appeal with the Service protesting the proposed adjustment of $1.1 million. The Company intends to vigorously contest the adjustment proposed by the Service and believes that it will ultimately prevail in its position. The Company would expect the recording of any adjustment, if later determined to be required, to entail recognition of a deferred tax asset and a corresponding current liability for federal income taxes payable. Such an adjustment would generally not result in a charge to earnings except for amounts which might be assessed for penalties or interest on underpayment of current tax for the Company’s fiscal years ended December 31, 2004 and 2005. If a liability for penalties or interest were determined to be probable, the amounts of such penalties and/or interest would be charged to earnings. The Company believes that the effects of this matter will not have a material adverse effect on its financial position or results of operations for any fiscal year, but could have a material adverse effect on its results of operations for the fiscal quarter in which it actually incurs or establishes a liability for penalties or interest.
	On January 1, 2005 the Company established a 401(k) Plan and Trust for eligible employees. During 2007, 2006 and 2005, the Company contributed an aggregate of approximately $274 000, $240,000 and $168,000, respectively, to the 401(k) Plan.
	The Company leases office space under a non-cancelable operating lease expiring in 2010. Future annual payments under this operating lease are approximately $200,000, $200,000 and $33,000 for the years ending December 31, 2008 through February 28, 2010, respectively. Rental expense under the Company’s current lease totaled approximately $200,000, $194,000 and $162,000 for the years ended December 31, 2007, 2006, and 2005, respectively.
	The Company has three field offices and storage facilities. These facilities are located in Andrews and Snyder, Texas and Hagerman, New Mexico. The Snyder office lease expires upon the cessation of production from the Diamond “M” area wells. Future annual payments under this lease agreement total approximately $14,000 for 2008 through 2012. Rental expense totaled approximately $23,000, $23,000 and $23,000 for the years ended December 31, 2007, 2006 and 2005, respectively.

F-31

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	The Company has an Incentive and Retention Plan which provides for the payment to eligible officers and employees of a one time performance bonus and retention payment upon the occurrence of a change of control as defined in the Plan. Because of the uncertainty of the occurrence of a change of control or corporate transaction within the meaning of the plan, the amount of these bonuses is undeterminable. Although the amount of the bonus is undeterminable at this time, if the bonus was calculated using the December 31, 2007 stock price of $17.63 per share, the amount would be approximately $18.6 million.
	In January 2006, the Company adopted a Non-officer Employee Severance Plan for the purpose of providing the Company’s non-officer employees with an incentive to remain employed with the Company. This Plan provides for a one-time severance payment to the non-officer employees equal to one year of their then “current base salary” upon the occurrence of a change of control within the meaning of the Plan. Based on the aggregate non-officer base salaries in effect as of December 31, 2007, the total severance amount payable under the plan would have been approximately $3.8 million.
(16)	Supplemental Oil and Natural Gas Reserve Data (Unaudited)
	The Company has presented the reserve estimates utilizing an oil price of $89.93, $54.67 and $56.09 per Bbl and a natural gas price of $6.77, $5.00 and $8.68 per Mcf as of December 31, 2007, 2006 and 2005, respectively. Information for oil is presented in barrels (Bbl) and for natural gas in thousands of cubic feet (Mcf).
	The estimates of the Company’s proved oil and natural gas reserves and related future net cash flows that are presented in the following tables are based upon estimates made by independent petroleum engineering consultants.
	The Company’s reserve information was prepared by independent petroleum engineering consultants as of December 31, 2007, 2006 and 2005. The Company cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates, and timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods.

F-32

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A summary of changes in reserve balances is presented below:

	Oil and Condensate (Bbls)
	For the Year Ended December 31,
	2007			2006			2005
	(In thousands)
Proved developed and undeveloped reserves
Beginning of year		28,721			21,192			18,916
Purchase of oil and natural gas properties		—			3,270			2,299
Sales of oil and natural gas properties		(75	)		—			(14	)
Extensions and discoveries		1,146			8,182			944
Revisions of previous estimates		(307	)		(2,786	)		(30	)
Production		(1,051	)		(1,137	)		(923	)
End of Year		28,434			28,721			21,192
Proved developed reserves at year end		14,378			14,932			13,614

	Natural Gas (MCF)
	For the Year Ended December 31,
	2007			2006			2005
	(In thousands)
Proved developed and undeveloped reserves
Beginning of year		58,896			25,237			16,825
Purchase of oil and natural gas properties		—			4,355			456
Sales of oil and natural gas properties		(3,105	)		—			(205	)
Extensions and discoveries		25,905			38,159			13,106
Revisions of previous estimates		(17,040	)		(2,316	)		(1,353	)
Production		(7,422	)		(6,539	)		(3,592	)
End of Year		57,234			58,896			25,237
Proved developed reserves at year end		41,556			28,741			17,246

The Company made significant acquisitions in 2005 and 2006 that resulted in additions to its estimated proved reserves for those years. In 2005, the Company purchased producing properties in the Harris San Andres Field located in Andrews and Gaines counties. In 2006, the Company acquired additional interests in these properties. Also in 2006, the Company purchased additional interests in the Barnett Shale Gas Project located in Tarrant County, Texas.

The Company’s drilling programs over the last three years have resulted in significant natural gas discoveries and extensions in the Company’s Barnett Shale resource gas project and the Company’s New Mexico projects. Over this same time period, the Company’s drilling in the Carm-Ann, Harris and Diamond M fields of west Texas resulted in significant increases in extensions and discoveries in the Company’s oil reserves.

The Company experienced downward revisions in estimated proved natural gas reserves in 2007. This was the result of two factors. First, the Company changed its method of recognizing proved undeveloped reserves related to its horizontal drilling gas projects in March 2007. Under this new method, which the Company believes conforms with regulatory requirements applicable to “horizontal well” reserve booking practices for publicly owned exploration and production companies, estimates of proved undeveloped reserves from horizontal wells are limited to two parallel offset wells to a productive horizontal well, unless productive continuity is demonstrated through pressure communication between wells more than an offset location away and on either side of a future horizontal well. Secondly, the Company adjusted its reserve estimates on certain New Mexico Wolfcamp and Barnett Shale wells where performance did not meet our 2007 production estimates.

The following is a standardized measure of the discounted net future cash flows and changes applicable to proved oil and natural gas reserves required by Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities (SFAS No. 69). The future cash flows are based on estimated oil and natural gas reserves utilizing prices and costs in effect as of year end, discounted at 10% per year and assuming continuation of existing economic conditions.

F-33

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of the Company’s proved oil and natural gas properties.

Future income tax expense was computed by applying statutory rates less the effects of tax credits for each period presented to the difference between pre-tax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties and available net operating loss and percentage depletion carryovers.

Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
($ in thousands)

	December 31,
	2007			2006			2005
Future cash inflows	$	2,944,746		$	1,864,860		$	1,407,153
Future costs:
Production		(824,261	)		(606,138	)		(361,563	)
Development		(117,981	)		(138,715	)		(36,335	)
Future income taxes		(536,227	)		(292,954	)		(249,621	)
Future net cash flows		1,466,277			827,053			759,634
10% annual discount for estimated timing of cash flows		(831,839	)		(490,565	)		(398,844	)
Standardized measure of discounted future net cash flows	$	634,438		$	336,488		$	360,790

Changes in Standardized Measure of
Discounted Future Net Cash Flows From Proved Reserves
($ in thousands)

	December 31,
	2007			2006			2005
Increase (decrease):
Purchases of minerals in place	$	—		$	20,698		$	29,354
Extensions and discoveries and improved recovery, net of future production and development costs		97,918			104,622			87,790	(1)
Accretion of discount		46,996			47,281			26,625
Net change in sales prices net of production costs		341,421			(78,387	)		135,242
Changes in estimated future development costs		28,424			12,726			(10,886	)
Revisions of quantity estimates		(64,408	)		(44,561	)		(4,518	)
Net change in income taxes		(116,010	)		(21,452	)		(52,181	)
Sales, net of production costs		(89,818	)		(86,130	)		(47,974	)
Changes of production rates (timing) and other		53,427			20,901			(9,071	)(1)
Net increase		297,950			(24,302	)		154,381
Standardized measure of discounted future net cash flows:
Beginning of year		336,488			360,790			206,409
End of year	$	634,438		$	336,488		$	360,790

⁽¹⁾ During 2006, the Company revised its method of calculating “Extensions and discoveries and improved recovery, net of future production and development costs”. Consequently, related calculations in 2005 have been adjusted to be consistent with the 2006 calculation.

F-34

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(17) Selected Quarterly Financial Data (Unaudited)

	Quarter
	First			Second		Third		Fourth
	($ in thousands, except per share data)
2007
Oil and natural gas revenues	$	23,116		$	27,354	$	29,487	$	36,074
Total costs and expenses		14,827			15,291		18,206		18,742
Operating income		8,289			12,063		11,281		17,332
Net income (loss)	$	(96	)	$	3,464	$	293	$	(8,322	)
Net income (loss) available to common stockholders	$	(96	)	$	3,464	$	293	$	(8,322	)
Net income per common share — basic	$	—		$	0.09	$	0.01	$	(0.21	)
Net income per common share — diluted	$	—		$	0.09	$	0.01	$	(0.21	)
2006
Oil and gas revenues	$	20,543		$	26,342	$	26,211	$	23,929
Total costs and expenses		11,102			13,962		16,686		14,856
Operating income		9,441			12,380		9,525		9,073
Net income	$	1,611		$	2,464	$	10,996	$	11,084	(1)
Net income available to common stockholders	$	1,611		$	2,464	$	10,996	$	11,084	(1)
Net income per common share — basic	$	0.05		$	0.07	$	0.30	$	0.30	(1)
Net income per common share — diluted	$	0.05		$	0.07	$	0.30	$	0.29	(1)

⁽¹⁾ 2006 results include $9.0 million of equity in income of pipeline and gathering systems representing the Company’s share of net gain on sale of certain pipeline assets. See Note 7.

F-35

SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PARALLEL PETROLEUM CORPORATION
February 20, 2008	By:	/s/ Larry C. Oldham
		Larry C. Oldham
		President and Chief Executive Officer
February 20, 2008	By:	/s/ Steven D. Foster
		Steven D. Foster
		Chief Financial Officer

S-1

     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

/s/ Jeffrey G. Shrader	Director and Chairman of the Board of Directors	February 20, 2008
Jeffrey G. Shrader
/s/ Larry C. Oldham	President and Chief Executive Officer	February 20, 2008
Larry C. Oldham	(Principal Executive Officer)
/s/ Steven D. Foster	Chief Financial Officer	February 20, 2008
Steven D. Foster	(Principal Financial and Accounting Officer)
/s/ Edward A. Nash	Director	February 20, 2008
Edward A. Nash
/s/ Martin B. Oring	Director	February 20, 2008
Martin B. Oring
/s/ Ray M. Poage	Director	February 20, 2008
Ray M. Poage

S-2

INDEX TO EXHIBITS

(a) Exhibits

No.	Description of Exhibit
3.1	Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)
3.2	Bylaws of Registrant (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on November 30, 2007)
3.3	Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
3.4	Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.4 of the Registrant’s Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
3.5	Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.5 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
3.6	Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
4.1	Certificate of Designations, Preferences and Rights of Serial Preferred Stock — 6% Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)
4.2	Certificate of Designations, Preferences and Rights of Series A Preferred Stock (Incorporated by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000)
4.3	Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the Registrant filed with the Securities and Exchange Commission on October 10, 2000)
4.4	Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No. 4.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
4.5	Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
4.6	Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
4.7	Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American Stock Transfer, Inc. (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
4.8	First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant, Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
4.9	Form of Rule 144A 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
4.10	Form of IAI 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
4.11	Form of Regulation S 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

No.	Description of Exhibit
4.12	Indenture, dated as of July 31, 2007, among the Registrant as Issuer and Wells Fargo Bank, National Association as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
4.13	Registration Rights Agreement, dated as of July 31, 2007, by and among the Registrant, Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities Corp. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
4.14	Purchase Agreement, dated as of July 26, 2007, by and among the Registrant, Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities Corp. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
4.15	Form of 101/4% Unrestricted Senior Note due 2014 (Incorporated by reference to Exhibit 4.13 of Form S-4 of the Registrant, Registration No. 333-148465)
Executive Compensation Plans and Arrangements (Exhibit No.’s 10.1 through 10.7):
10.1	1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
10.2	Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form 10-K for the fiscal year ended December 31, 1995)
10.3	Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005)
10.4	1998 Stock Option Plan (Incorporated by reference to Exhibit 10.4 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.5	2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form 10-Q Report for the fiscal quarter ended March 31, 2004)
10.6	2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated September 22, 2004)
10.7	Incentive and Retention Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.8	First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the Registrant, dated December 20, 2002)
10.9	Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December 20, 2002)
10.10	First Amendment to First Amended and Restated Credit Agreement, dated as of September 12, 2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003)
10.11	Second Amended and Restated Credit Agreement, dated September 27, 2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated September 27, 2004 and filed with the Securities and Exchange Commission on October 1, 2004)
10.12	Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
10.13	First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27, 2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas,

No.	Description of Exhibit
	Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated December 30, 2004 and filed with the Securities and Exchange Commission on December 30, 2004)
10.14	Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated April 4, 2005 and filed with the Securities and Exchange Commission on April 8, 2005)
10.15	Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated October 4, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.16	Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy, Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney, Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit 10.2 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.17	Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.18	Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.19	ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank, N.A. (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.20	Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas, CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrant’s Form 8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on December 30, 2005)
10.21	Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.4 of the Registrant’s Form 8-K Report, dated November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005)
10.22	Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas, N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C. (Incorporated by reference to Exhibit No. 10.5 of the Registrant’s Form 8-K Report, dated November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005)
10.23	Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.23 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.24	Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.24 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.25	Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

No.	Description of Exhibit
10.26	Third Amendment to Third Amended and Restated Credit Agreement, dated as of July 31, 2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K filed on August 1, 2007)
10.27	Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of November 30, 2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to Exhibit 10.27 of Form S-4 of the Registrant, Registration No. 333-148465)
*10.28	Hagerman Gas Gathering System Joint Venture Agreement, dated as of January 16, 2007, among the Registrant, Feagan Gathering Company and Capstone Oil & Gas Company, L.P.
14	Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrant’s Form 10-K Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange Commission on March 22, 2004)
*23.1	Consent of BDO Seidman, LLP
*23.2	Consent of Cawley Gillespie & Associates Inc. Independent Petroleum Engineers
*31.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes — Oxley Act of 2002.
*31.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes — Oxley Act of 2002.
*32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.
*32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.

* Filed herewith.

EX-10.28

Exhibit 10.28

JOINT VENTURE AGREEMENT

HAGERMAN GAS GATHERING SYSTEM

A Joint Venture Formed By

FEAGAN GATHERING COMPANY

PARALLEL PETROLEUM CORPORATION

and

CAPSTONE OIL & GAS COMPANY, L.P.

INDEX

Article 1	Formation of Joint Venture
1.1	Formation of Joint Venture	1
Article 2	Definitions
2.1	Definitions	1
2.2	Terms Generally	3
Article 3	The Joint Venture
3.1	Name, Assumed Name Certificates	4
3.2	Joint Venture Office and Principal Place of Business	4
3.3	Purpose	4
3.4	Other Activities	4
Article 4	Ownership and Availability of the System
4.1	Ownership of Joint Venture Facilities	5
4.2	Availability of the System	5
Article 5	Representations and Warranties
5.1	Representations, Warranties and Covenants of Parties	5
Article 6	Capital Contributions and Ownership
6.1	Initial Capital Contribution and Ownership	6
6.2	Additional Capital Contributions	7
6.3	Payment of Capital Contributions	7
6.4	Carried Capital Contribution	8
6.5	Option to Purchase Additional Interest	8
6.6	Voluntary Contributions	8
Article 7	Allocations and Capital Accounts
7.1	Allocations; Capital Accounts	9

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Article 8	Distributions and Reimbursements
8.1	Distributions	11
8.2	Reimbursement of Expenses	12
Article 9	Accounting; Books and Records; Taxes
9.1	Fiscal Year	12
9.2	Location of Records	12
9.3	Books of Account	12
9.4	Financial Statements	12
9.5	Taxation and Reports	13
9.6	Governmental Reports and Compliance with Laws	13
9.7	Inspection of Facilities and Records	14
9.8	Deposit of Funds	14
9.9	Tax Matters Partner	14
Article 10	Management; Operator and Conduct of Operations
10.1	Management of the Joint Venture	15
10.2	Operator	15
10.3	Composition of Management Committee	15
10.4	Authority of the Management Committee	15
10.5	Approval Requirements; Limitation on Voting Rights	17
10.6	Meetings	17
10.7	Appointment of Operator; Construction and Operation of the System	17
10.8	Conduct of Operations	17
10.9	Expenses	18
10.10	Personnel	18
10.11	Discharge of Expenses	18
10.12	Ad Valorem Taxes	18
10.13	Rights of Way	18
10.14	Removal and Replacement of Operator	19
Article 11	Liability and Indemnification of Joint Venturers; Insurance
11.1	Limitation of Liability of Joint Venturers	19
11.2	Insurance	20
11.3	Claims	20
11.4	Contractors and Subcontractors	21

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Article 12	Assignments
12.1	Limitation of Rights to Transfer Joint Venturers' Interests	21
12.2	Permitted Transfers by Joint Venturers	22
12.3	Effect of Permitted Transfers	22
12.4	Effects of Prohibited Transfers	22
Article 13	Term; Termination and Winding Up
13.1	Term	23
13.2	Voluntary Withdrawal of a Joint Venturer	23
13.3	Automatic Termination	23
13.4	Removal for Default	25
13.5	Remedies of Non-Withdrawing Party	26
13.6	Buy-Sell Procedures	26
13.7	Appraisal Procedure	28
13.8	Termination and Winding Up	29
13.9	Effect of Termination or Withdrawal	31
Article 14	Salvage
14.1	Abandonment	31
Article 15	Confidentiality
15.1	Confidentiality	32
Article 16	Miscellaneous
16.1	Notice	32
16.2	Further Assurance	33
16.3	Amendment	33
16.4	Waiver	33
16.5	Exhibits	33
16.6	Applicable Laws	34
16.7	Counterparts	34
16.8	Headings	34
16.9	Section Numbers	34
16.10	Entirety	34
16.11	Severability	34
16.12	Binding Effect; Joinder of Additional Parties	34

iii 

Article 17	Arbitration
17.1	General	34
17.2	Procedures	35
17.3	Specific Enforcement	36
Exhibit A	Construction and Operating Agreement
Exhibit B	Project Area
Exhibit C	Gas Gathering Agreement
Exhibit D	Insurance

iv  

HAGERMAN GAS GATHERING SYSTEM
JOINT VENTURE AGREEMENT

     THIS JOINT VENTURE AGREEMENT (this “Agreement”), dated as of January 16, 2007, to be effective from and after April 1, 2006, is made by and among Feagan Gathering Company, a Texas corporation (“Feagan”), Parallel Petroleum Corporation, a Delaware corporation (“Parallel”), and Capstone Oil & Gas Company, L.P., a Texas limited partnership (“Capstone”). Feagan, Parallel and Capstone are hereinafter sometimes referred to collectively as “Joint Venturers”, and each, individually, as a “Joint Venturer”.

WITNESSETH:

     WHEREAS, Feagan, Parallel and Capstone desire to join together for the purposes of constructing, managing, owning, leasing and operating a natural gas pipeline located in Chaves County, New Mexico, and further desire to set forth the terms and conditions upon which such activities will be conducted;

     NOW, THEREFORE, in consideration of the mutual covenants set forth herein, Feagan, Parallel and Capstone hereby agree as follows:

ARTICLE 1
FORMATION OF JOINT VENTURE

     1.1 Formation of Joint Venture. Feagan, Parallel and Capstone hereby enter into and form a joint venture for the limited purposes and scope set forth herein. Except as expressly provided for herein to the contrary, the rights and obligations of the Joint Venturers and the administration and termination of the Joint Venture shall be governed by the Texas General Partnership Law (the “TGPL”), part of the Texas Business Organizations Code. A Joint Venturer’s interest in the Joint Venture shall be personal property for all purposes. All real and other property owned by the Joint Venture shall be deemed owned by the Joint Venture as an entity, and no Joint Venturer, individually shall have any direct ownership in such property.

ARTICLE 2
DEFINITIONS

     2.1 Definitions. In addition to the terms defined elsewhere in this Agreement, the following terms shall have the respective meanings set forth below:

     Capital Contribution. The capital contributed to the Joint Venture by a Joint Venturer pursuant to Article 6 of this Agreement.

     Code. The Internal Revenue Code of 1986, as amended from time to time, and any successor statute or statutes.

     Construction and Operating Agreement. The Construction and Operating Agreement between the Joint Venture and the Person designated as Operator in accordance herewith, the form of which is attached hereto as Exhibit “A”.

     Cost of a Joint Venture Expansion. All costs, expenses and liabilities incurred or paid by the Joint Venture for the real and personal property acquisitions, planning, design, engineering and construction of a Joint Venture Expansion, and securing necessary governmental authorizations and approvals therefor.

     Cost of the System. All cost, expenses and liabilities incurred or paid by the Joint Venture for the real property (excluding the Project Area) and personal property acquisitions, planning, design, engineering and construction of the System, and securing necessary governmental authorizations and approvals therefor.

     Gas. Natural gas having the physical and chemical qualities required for acceptance by the Joint Venture.

     Joint Venture. The entity created by this Agreement, which the parties agree is a joint venture.

     Joint Venture Expansion. Any pipelines and appurtenances together with related facilities and properties (including, but not limited to, rental compression facilities), which expand the System.

     “Joint Venture Nonrecourse Liabilities” shall have the meaning assigned to the term “nonrecourse liabilities” in Treasury Regulation section 1.752-1(a)(2).

     Joint Venturer(s). The collective or individual reference, as the case may be, to each of the Joint Venturers executing this Agreement and any Joint Venturer admitted to the Joint Venture or substituted in place of an original Joint Venturer pursuant to Article 12; provided, however, that the term Joint Venturer shall not include any Person who shall be deemed to have withdrawn from the Joint Venture pursuant to Section 13.3(b).

     Joint Venture Percentage Interest. For each Joint Venturer, the percentage ownership of the Joint Venture based upon the proportion that such Joint Venturer’s

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Capital Contributions bears to the total Capital Contributions made by all Joint Venturer’s, including, in the case of Feagan, the Carried Capital Contribution provided for in Section 6.4.

     “Joint Venturer Nonrecourse Debt” shall have the meaning assigned to the term “partner nonrecourse debt” in Treasury Regulation section 1.704.2(b)(4).

     “Joint Venturer Nonrecourse Deductions” shall have the meaning assigned to the term “partner nonrecourse deductions” in Treasury Regulation section 1.704-2(i).

     Management Committee. The Management Committee provided for in Section 10.3.

     “Minimum Gain” shall have the meaning assigned to that term in Treasury Regulation section 1.704-2(d) and section 1.704-2(i)(3), as applicable.

     Operator. The Operator provided for in Section 10.2.

     Person. An individual, a corporation, voluntary association, joint stock company, business trust, partnership or other entity.

     Project Area. The leasehold acreage situated in Chaves County, New Mexico that is subject, from time to time, to the area of mutual interest contained in that certain Exploration Agreement, dated as of March 1, 2004, between Parallel and Capstone and that is owned beneficially or of record by Parallel and Capstone and dedicated by Parallel and Capstone to the System, as further described on Exhibit “B” attached hereto and made a part hereof.

     System. The pipeline and appurtenant and related facilities owned by the Joint Venture, including any Joint Venture Expansion.

     “Treasury Regulations” (or any abbreviation thereof used herein) shall mean temporary or final regulations promulgated under the Code.

     2.2 Terms Generally. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”. Unless the context requires otherwise (a) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments,

3

supplements or modifications set forth herein), (b) any reference herein to any Person shall be construed to include such Person’s successors and assigns, provided such successors and assigns are permitted by this Agreement, (c) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, and (d) all references herein to Articles, Sections, exhibits and schedules shall be construed to refer to Articles and Sections of, and exhibits and schedules to, this Agreement.

ARTICLE 3
THE JOINT VENTURE

     3.1 Name; Assumed Name Certificates. The name of the Joint Venture shall be Hagerman Gas Gathering System. The Joint Venturers shall execute all assumed or fictitious name certificates required by law to be filed in connection with the formation of the Joint Venture and the conduct of its business and shall cause such certificates to be filed in the applicable records of each state where the Joint Venture conducts business.

     3.2 Joint Venture Office and Principal Place of Business. The principal offices and principal place of business of the Joint Venture shall be located at 1004 N. Big Spring, Suite 400, Midland, Texas 79701.

     3.3 Purpose. The purpose of the Joint Venture shall be to plan, design, obtain any necessary governmental approval for, construct, own and operate the System for the purchase and sale or transport of Gas produced from the Project Area.

     3.4 Other Activities. Nothing contained in this Agreement shall be construed to prohibit any Joint Venturer or any firm or corporation controlled by or controlling any Joint Venturer from owning, operating or investing in any natural gas pipeline other than the System or from engaging in any business similar to or in competition with the Joint Venture. Each Joint Venturer agrees that the other Joint Venturers or any affiliate thereof may engage in or possess any interest in any other business venture or ventures of any nature and description independently or with others, including, but not limited to, the sale and purchase of natural gas, the ownership, financing, leasing, construction, operation, sale, maintenance, management, syndication, brokerage and development of natural gas pipeline systems and no Joint Venturer shall have any rights by virtue of this Agreement in and to said other business venture or ventures or the income or profits derived therefrom.

4

ARTICLE 4
OWNERSHIP AND AVAILABILITY OF THE SYSTEM

     4.1 Ownership of Joint Venture Facilities. Title to Joint Venture property, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Joint Venture as an entity, and no Joint Venturer, individually or collectively, shall have any ownership interest in such Joint Venture property or any portion thereof. Title to any or all of the Joint Venture property may be held in the name of the Joint Venture or one or more nominees, as the Management Committee may determine. Upon the withdrawal or removal of any Joint Venturer or as soon thereafter as practicable, the withdrawing or removed Joint Venturer holding title to any Joint Venture property as nominee for the Joint Venture shall transfer to the Joint Venture record title to such property and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the Joint Venture. All Joint Venture property shall be recorded as the property of the Joint Venture in its books and records, irrespective of the name in which record title to such Joint Venture property is held. Although the Project Area is dedicated to the facilities included in the System, ownership of the Project Area shall remain the sole property of each respective Joint Venturer having record or beneficial ownership thereof, subject to each such Joint Venturer’s right to sell, transfer and convey all or any portion of the Project Area owned by such Joint Venturer, at any time and from time to time. As natural gas reserves are developed in the Project Area by the Joint Venturers or by third parties, the Joint Venturers anticipate that gathering lines will need to be constructed from time to time to connect the producing areas within the Project Area. Such facilities are contemplated by the Joint Venturers to be part of the System. If any such facilities are acquired or constructed by the Joint Venture, the same will thereupon become a part of the System. No other facilities, whether existing facilities owned by any of the Joint Venturers or subsequently acquired or constructed by any of the Joint Venturers are or shall be the subject of this Agreement, except for those which are located within the Project Area.

     4.2 Availability of the System. First priority to the availability and capacity of the System shall be given to the Gas produced in the Project Area by Parallel and Capstone, and their respective successors and assigns, and gathered pursuant to that certain Gas Gathering Agreement, dated or to be dated of even date herewith, among Parallel, Capstone and the Joint Venture, and being in substantially the form attached hereto as Exhibit “C”.

ARTICLE 5
REPRESENTATIONS AND WARRANTIES

     5.1 Representations, Warranties and Covenants of Parties. Each Joint Venturer represents and warrants to the other, and agrees that:

5

     (a) It is a corporation or limited partnership duly organized and validly existing under the laws of its jurisdiction of organization.

     (b) If it is organized under the laws of a jurisdiction other than Texas, it is duly qualified or authorized to do business in Texas.

     (c) It will not cause a dissolution or termination of the Joint Venture by reason of the failure to maintain its corporate or partnership existence, except as otherwise permitted herein.

     (d) The execution and delivery of this Agreement has been duly authorized, and this Agreement, when executed and delivered, will be valid and binding on it.

     (e) The execution and delivery of this Agreement, the formation of the Joint Venture and the performance hereof will not contravene any provision of, or constitute a default under, any indenture, mortgage or other material agreement to which it is a party or by which its assets may be bound, or any order of any court, commission or governmental agency having jurisdiction.

     (f) The Joint Venture is an “intrastate pipeline”, as defined in the Natural Gas Policy Act of 1978, as hereto or hereafter amended, and will not, through any act or omission, cause or contribute to causing itself, the Joint Venture, or any other Joint Venturers, or any of the facilities of any of them to become subject in whole or in part to the jurisdiction of the Federal Energy Regulatory Commission or any successor thereto, under the Federal Energy Regulatory Commission’s jurisdiction under the Natural Gas Policy Act of 1978 and the Natural Gas Act, as hereto or hereafter amended.

     (g) There are no claims for brokerage or other commission or finder’s or other similar fees in connection with the transactions covered by this Agreement insofar as such claims may be based on arrangements or agreements made by or on its behalf, and each Joint Venturer hereby agrees to indemnify and hold harmless the other from and against all liabilities, costs, damages and expenses from any such claims.

ARTICLE 6
CAPITAL CONTRIBUTIONS AND OWNERSHIP

     6.1 Initial Capital Contribution and Ownership. Promptly after receipt of a written request from the Operator given in accordance with Section 6.3, each Joint Venturer shall make its respective initial Capital Contribution to the Joint Venture, including each Joint Venturer’s obligation to contribute a total amount equal to its Joint Venture Percentage Interest of $5,500,000. Subject to Section 6.5 hereof, the Joint Venture Percentage Interest of each Joint Venturer is as follows:

6

Feagan	10.00	%
Parallel	76.50	%
Capstone	13.50	%

     6.2 Additional Capital Contributions. From time to time, whenever any part of the System or a Joint Venture Expansion shall be authorized by the Management Committee, each Joint Venturer shall contribute additional capital to the Joint Venture in an amount equal to its Joint Venture Percentage Interest of the Cost of the System or the Cost of a Joint Venture Expansion, as the case may be. Each Joint Venturer shall be obligated to make such additional Capital Contributions in the amount set forth in construction fund schedules prepared from time to time by the Operator and approved by the Management Committee in connection with the System and each Joint Venture Expansion pursuant to Section 10.4 hereof. Additional Capital Contributions to be made pursuant to this Section 6.2 shall be made in accordance with Section 6.3 hereof.

     6.3 Payment of Capital Contributions. Except as may be otherwise determined by the Management Committee:

     (a) The Operator shall issue or cause to be issued a written request for payment of each Capital Contribution to be made in accordance with Sections 6.1 and 6.2, at such times and in such incremental amounts as may be requested by the Operator from time to time, but only after approval of the Management Committee.

     (b) Each written request issued pursuant to this Section 6.3 shall contain the following information:

(i)	the amount of the Capital Contribution requested from each Joint Venturer, which amount shall equal such Joint Venturer’s Percentage of the total Capital Contributions then requested of the Joint Venturers;
(ii)	the purposes for which the Capital Contributions are to be applied; and
(iii)	the date on which the Capital Contributions shall be made (which shall not be less than thirty (30) days following the date the request is made) and the method of payment, such date and method to be identical for all of the Joint Venturers.

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     (c) Each Joint Venturer agrees to make payment of its respective Capital Contributions in accordance with the requests made by the Operator pursuant to this Agreement.

     6.4 Carried Capital Contribution. Subject to the last sentence of this Section 6.4, Parallel and Capstone shall pay, or “carry”, for the benefit of Feagan a portion of the Capital Contribution that would otherwise be required to be made by Feagan under the terms of this Agreement. The amount required to be paid, or “carried”, by Parallel and Capstone shall be an amount equal to fifty percent (50.0%) of the Capital Contributions that would otherwise be required to be made by Feagan under the terms of this Agreement (the “Carried Capital Contribution”). The Carried Capital Contribution provided for in this Section 6.4 shall be allocated between Parallel and Capstone based upon their respective Joint Venture Percentage Interests (with Parallel initially paying for eighty five percent (85%) of such Carried Capital Contribution and Capstone initially paying for the remaining fifteen percent (15%) of such Carried Capital Contribution). The obligation of Parallel and Capstone to fund and pay for the Carried Capital Contribution shall be limited to the first ten million dollars ($10,000,000.00) of capital expenditures made by the Joint Venture in connection with this Agreement.

     6.5 Option to Purchase Additional Interest. Until the close of business on March 31, 2007, Feagan shall have a one-time option to purchase from Parallel and Capstone a five percent (5%) interest in the Joint Venture. If Feagan elects to exercise such option, it shall give written notice thereof to Parallel and Capstone on or before the close of business on March 31, 2007. The total purchase price for such interest shall be equal to the sum of (a) (i) the aggregate Capital Contributions attributable to a five percent (5.0%) ownership interest (the “Option Purchase Price”) in the Joint Venture up to and including the date of exercise of the option, and (ii) an additional five and one-half percent (5.5%) of the Option Purchase Price, less (b) the amount of any distributions made by the Joint Venture to Feagan prior to the date of exercise of the option. The purchase price shall be paid within ten (10) days after Feagan gives notice to Parallel and Capstone of its election to exercise such option. The five percent (5%) ownership interest in the Joint Venture that is subject to the option provided for in this Section 6.5 shall be allocated between Parallel and Capstone based upon their respective Joint Venture Percentage Interests (with Parallel initially being obligated to deliver and convey eighty five percent (85%) of the five percent (5%) interest and Capstone being obligated to deliver and convey the remaining fifteen percent (15%) of the five percent (5%) interest).

     6.6 Voluntary Contributions. No Joint Venturer shall make any Capital Contributions to the Joint Venture except pursuant to a request of the Operator given in accordance with Section 6.3.

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ARTICLE 7
ALLOCATIONS AND CAPITAL ACCOUNTS

     7.1 Allocations; Capital Accounts.

     (a) For accounting and federal and state income tax purposes, except as herein otherwise specifically provided, or as may be required by Section 704(c) of the Code and Treasury Regulation section 1.704-1(b)(2)(iv)(f)(4), all costs, expenditures, income, deductions, credits, gains and losses of the Joint Venture shall be allocated to the Joint Venturers in accordance with their respective Joint Venture Percentage Interest. Any item which is stipulated to be an expense of the Joint Venture under the terms of this Agreement or which would be so treated in accordance with generally accepted accounting principles shall be treated as an expense of the Joint Venture for all purposes, whether or not such item is deductible for purposes of computing net income for federal income tax purposes. Neither the allocations referred to in this Section 7.1 nor the utilization of varying tax bases as herein provided shall have any effect whatsoever upon any Joint Venturer’s Joint Venture Percentage Interest.

     (b) Notwithstanding any of the foregoing provisions of this Section 7.1 to the contrary:

     (i) If during any fiscal year of the Joint Venture there is a net increase in Minimum Gain attributable to a Joint Venturer Nonrecourse Debt that gives rise to Joint Venturer Nonrecourse Deductions, each Joint Venturer bearing the economic risk of loss for such Joint Venturer Nonrecourse Debt shall be allocated items of Joint Venture deductions and losses for such year (consisting first of cost recovery or depreciation deductions with respect to property that is subject to such Joint Venturer Nonrecourse Debt and then, if necessary, a pro rata portion of the Joint Venture’s other items of deductions and losses, with any remainder being treated as an increase in Minimum Gain attributable to Joint Venturer Nonrecourse Debt in the subsequent year) equal to such Joint Venturer’s share of Joint Venturer Nonrecourse Deductions, as determined in accordance with applicable Treasury Regulations.

     (ii) If for any fiscal year of the Joint Venture there is a net decrease in Minimum Gain attributable to Joint Venture Nonrecourse Liabilities, each Joint Venturer shall be allocated items of Joint Venture income and gain for such year (consisting first of gain recognized from the disposition of Joint Venture property subject to one or more Joint Venture Nonrecourse Liabilities and then, if necessary, a pro rata portion of the Joint Venture’s other items of income and gain, and then, if necessary, for subsequent years) equal to such Joint Venturer’s share

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of such net decrease (except to the extent such Joint Venturer’s share of such net decrease is caused by a change in debt structure with such Joint Venturer commencing to bear the economic risk of loss as to all or part of any Joint Venture Nonrecourse Liability or by such Joint Venturer contributing capital to the Joint Venture that the Joint Venture uses to repay a Joint Venture Nonrecourse Liability), as determined in accordance with applicable Treasury Regulations.

     (iii) If for any fiscal year of the Joint Venture there is a net decrease in Minimum Gain attributable to a Joint Venturer Nonrecourse Debt, each Joint Venturer bearing the economic risk of loss for such Joint Venturer Nonrecourse Debt shall be allocated items of Joint Venture income and gain for such year (consisting first of gain recognized from the disposition of Joint Venture property subject to Joint Venturer Nonrecourse Debt, and then, if necessary, a pro rata portion of the Joint Venture’s other items of income and gain, and if necessary, for subsequent years) equal to such Joint Venturer’s share of such net decrease (except to the extent such Joint Venturer’s share of such net decrease is caused by a change in debt structure or by the Joint Venture’s use of capital contributed by such Joint Venturer to repay the Joint Venturer Nonrecourse Debt) as determined in accordance with applicable Treasury Regulations.

     (c) The losses and deductions allocated pursuant to this Article 7 shall not exceed the maximum amount of losses and deductions that can be allocated to a Joint Venturer without causing or increasing a deficit balance in the Joint Venturer’s adjusted capital account. If, at the end of any fiscal year, as a result of the allocations otherwise provided for in this Section 7.1, the adjusted capital account balance of any Joint Venturer shall become negative, items of deduction and loss otherwise allocable to such Joint Venturer for such year, to the extent such items would have caused such negative balance, shall instead be allocated to Joint Venturers having positive adjusted capital account balances remaining at such time in proportion to such balance.

     (d) If a Joint Venturer unexpectedly receives any adjustment, allocation or distribution described in Treasury Regulations section 1.704-1(b)(2)(ii)(d)(4)-(6) that causes or increases a deficit balance in such Joint Venturer’s adjusted capital account, items of Joint Venture income and gain shall be allocated to that Joint Venturer in an amount and manner sufficient to eliminate the deficit balance as quickly as possible.

     (e) The allocations set forth in subsections (b), (c) (last sentence), and (d) (collectively, the “Regulatory Allocations”) are intended to comply with certain requirements of the Treasury Regulations. It is the intent of the Joint Venturers that, to the extent possible, all Regulatory Allocations that are made be offset either with other Regulatory Allocations or with special allocations pursuant to this Section 7.1(g).

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Therefore, notwithstanding any other provisions of this Article 7 (other than the Regulatory Allocations), Parallel shall make such offsetting special allocations in whatever manner it determines appropriate so that, after such offsetting allocations are made, each Joint Venturer’s adjusted capital account balance is, to the extent possible, equal to the adjusted capital account balance such Joint Venturer would have had if the Regulatory Allocations were not part of this Agreement and all Joint Venture items were allocated pursuant to the remaining sections of this Article 7.

     (f) In accordance with Section 704(c) of the Code and the Treasury Regulations thereunder, income and deductions with respect to any property carried on the books of the Joint Venture at an amount that differs from such property’s adjusted tax basis shall, solely for federal income tax purposes, be allocated among the Joint Venturers in a manner to take into account any variation between the adjusted tax basis of such property to the Joint Venture and such book value. In making such allocations, Parallel shall use the “traditional method with curative allocations” pursuant to Treasury Regulations Section 1-704-3(c).

     (g) All items of income, gain, loss, deduction, and credit allocable to any Joint Venture Percentage Interest that may have been transferred shall be allocated between the transferor and transferee based on the portion of the calendar year during which each was recognized as owning those Joint Venture Percentage Interests, without regard to whether cash distributions were made to the transferor or the transferee during that calendar year; provided, however, that this allocation must be made in accordance with a method permissible under section 706 of the Code and the applicable Treasury Regulations.

     (h) A capital account shall be maintained for each Joint Venturer, which account shall be increased (credited) by (i) the cash and adjusted tax basis of property contributed by it to the Joint Venture (net of liabilities assumed by the Joint Venture and liabilities to which such contributed property is subject), and (ii) the distributive share of net income and gain (including income exempt from tax) allocated to such Joint Venturer, and shall be decreased (debited) by (iii) the cash and the Joint Venture’s adjusted tax basis of property distributed to such Joint Venturer (net of liabilities assumed by such Joint Venturer and liabilities to which such distributed property is subject), (iv) the amount of net loss allocated to such Joint Venturer, and (v) such Joint Venturer’s distributive share of expenditures of the Joint Venture.

ARTICLE 8
DISTRIBUTIONS AND REIMBURSEMENTS

     8.1 Distributions. Distributions of excess cash to the Joint Venturers shall only be made to the Joint Venturers simultaneously in such aggregate amounts and at such

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times as determined by the Management Committee from time to time. Distributions of cash shall be made to the Joint Venturers in the same manner that items of cost, expenditure, income, gain, loss, deduction and credit are allocated to the Joint Venturers under Section 7.1.

     8.2 Reimbursement of Expenses. The Joint Venture shall pay or reimburse the Joint Venturers all reasonable direct and indirect costs incurred by them in managing and conducting the business and affairs of the Joint Venture, including, without limitation, (i) all costs and expenses incurred in any business of the Joint Venture, (ii) secretarial, telephone, office rent and other office expenses, (iii) salaries and other compensation expenses of employees of any Joint Venturer, (iv) other administrative expenses, (v) travel expenses, (vi) legal and accounting costs and expenses, and (vii) expenses incurred in providing or obtaining such other professional, technical, administrative services and advice as the Management Committee may deem necessary or desirable. The Management Committee shall determine in good faith which expenses are allocable to the Joint Venture in a manner which is fair and reasonable to the Joint Venture.

ARTICLE 9
ACCOUNTING; BOOKS AND RECORDS; TAXES

     9.1 Fiscal Year. The fiscal year of the Joint Venture shall be the calendar year.

     9.2 Location of Records. The books and records of the Joint Venture shall be kept and maintained at the Joint Venture’s office.

     9.3 Books of Account. The books of account for the Joint Venture shall be kept and maintained at the principal place of business of Parallel. The books of account shall be maintained on an accrual basis in accordance with generally accepted accounting principles, consistently applied, and shall show all items of income and expense.

     9.4 Financial Statements. Parallel shall prepare and furnish or cause to be prepared and furnished to the Joint Venturers, within forty (40) days after the close of each fiscal quarter of the Joint Venture, financial statements showing the financial condition and results of operations of the Joint Venture for such fiscal quarter, which statements shall include the balance in each Joint Venturer’s Capital Account, the unpaid balance due under all obligations of the Joint Venture, a statement of profit and loss and all other information, financial or otherwise, as may be necessary for any Joint Venturer to comply with various reporting and disclosure requirements of governmental agencies to which it may be subject, and all other information reasonably requested by a Joint Venturer. Parallel shall cause to be prepared and furnished, at the expense of the Joint Venture, to each of the Joint Venturers within seventy-five (75) days after the end of each

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fiscal year, financial statements showing the financial condition and results of operations of the Joint Venture as of and for the twelve (12) month period ending on the last day of December of each year, which year-end statements may, at the sole election of Parallel, be audited by such independent registered public accounting firm as Parallel may engage for and on behalf of the Joint Venture and certified by such independent registered public accounting firm as having been prepared in accordance with generally accepted accounting principles consistently applied.

     In addition, Parallel will cause to be prepared and furnished to each Joint Venturer such other accounting and tax information as shall be necessary for the preparation by each Joint Venturer of its income tax returns for each fiscal year.

     9.5 Taxation and Reports.

     (a) Any provision hereof to the contrary notwithstanding, solely for United States federal income tax purposes, each of the Joint Venturers hereby recognizes that the Joint Venture will be subject to all provisions of Subchapter K of Chapter 1 of Subtitle A of the Code; provided, however, the filing of U.S. Partnership Returns of Income shall not be construed to extend the purposes of the Joint Venture or expand the obligations or liabilities of the Joint Venturers. At the request of any Joint Venturer, the Joint Venture shall file an election under Section 754 of the Code.

     (b) Parallel shall prepare or cause to be prepared all federal and state income tax returns and related schedules and statements, and cause to be made all elections, if any, which must be filed on behalf of the Joint Venture with any taxing authority and shall submit such returns and related schedules and statements to all the Joint Venturers for their approval on or about March 15 of each year, and, upon approval thereof by all the Joint Venturers, make timely filing thereof.

     9.6 Governmental Reports and Compliance with Laws.

     (a) The Operator shall be responsible for all reports required of it by state and federal authorities on account of operations related to the System. However, each Joint Venturer shall be and remains solely responsible for all reports and accounts required by state and federal authorities on account of production delivered by it to the System, and for the payment of all royalties, overriding royalties, or payments from production with respect to all production owned by it and delivered to or handled by the System, and Operator shall have no rights or duties in connection therewith.

     (b) The Operator, on behalf of the Joint Venture, shall obtain such permits and approvals from governmental authorities having jurisdiction over the business and affairs

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of the Joint Venture as may be necessary or advisable to construct and operate the System and to transport Gas.

     (c) The Operator shall at all times comply with all applicable rules, regulations, laws, orders, ordinances, decrees or other matters promulgated or administered by any governmental or quasi-governmental body with jurisdiction over the System or the ownership or operation thereof.

     9.7 Inspection of Facilities and Records. Each Joint Venturer shall have the right at all reasonable times during usual business hours to inspect the facilities of the Joint Venture and to examine, audit and make copies of the books of account and other records of the Joint Venture. Such right may be exercised through any agent or employee of a Joint Venturer designated in writing by it or by an independent public accountant, petroleum engineer, attorney or other consultant designated by such Joint Venturer. Each Joint Venturer shall bear all costs and expenses incurred in any inspection, examination or audit made for such Joint Venturer’s account.

     9.8 Deposit of Funds. The funds of the Joint Venture shall be deposited in a separate account with such banks or other financial institutions as may be designated from time to time by the Management Committee. The Management Committee from time to time shall authorize signatories for such accounts.

     9.9 Tax Matters Partner. Parallel shall act as the “tax matters partner” under Section 6231 of the Code (Parallel, in this Section, being called the “tax matters partner”). The tax matters partner shall promptly notify the Joint Venturers if any tax return or report of the Joint Venture is audited or if any adjustments are proposed by any governmental body. In addition, the tax matters partner shall promptly furnish to the Joint Venturers all notices concerning administrative or judicial proceedings relating to federal income tax matters as required under the Code. During the pendency of any such administrative or judicial proceeding, the tax matters partner shall furnish to the Joint Venturers periodic reports, not less often than monthly, concerning the status of any such proceeding. Without the consent of the Management Committee, the tax matters partner shall not extend the statute of limitations, file suit concerning any tax refund or deficiency relating to any Joint Venture administrative adjustment or enter into any settlement agreement relating to any Joint Venture item of income, gain, loss, deduction or credit for any fiscal year of the Joint Venture.

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ARTICLE 10
MANAGEMENT; OPERATOR AND CONDUCT OF OPERATIONS

     10.1 Management of the Joint Venture. The overall management and control of the business and affairs of the Joint Venture shall be vested in the Joint Venturers and, except where herein expressly provided to the contrary, all decisions with respect to the management and control of the Joint Venture shall be made and approved by the Management Committee as provided in Section 10.4 below.

     10.2 Operator. The Operator of the System shall devote such time to the Joint Venture’s business as it deems necessary to manage and supervise the System in an efficient manner. The Operator shall, subject to the control and direction of the Management Committee, be responsible for the implementation of the decisions of and actions approved by the Management Committee, and in general supervise and control the System and perform all duties and exercise all powers as the Management Committee may delegate to the Operator from time to time, subject to the provisions of applicable law, this Agreement and the Construction and Operating Agreement. In addition, and subject to the provisions hereof, the Operator shall have and perform the duties and obligations specified in the Construction and Operating Agreement.

     10.3 Composition of Management Committee. The members of the Management Committee shall consist of one representative appointed by each Joint Venturer. Each Joint Venturer shall designate in writing its representative to serve on the Management Committee. If any representative appointed by a Joint Venturer fails, refuses or is unable to serve on the Management Committee for any reason, then the Joint Venturer that appointed such representative may appoint and designate an alternate representative who shall serve on the Management Committee in place of the previously appointed representative. Any Joint Venturer may at any time, by written notice to each other Joint Venturer, remove its representative on the Management Committee and appoint a new representative.

     10.4 Authority of the Management Committee. Except as otherwise expressly provided in this Agreement, the approval of the Management Committee shall be necessary before any action can be taken by the Joint Venture or any Joint Venturer (including the Operator) on behalf of the Joint Venture. Without limiting the generality of the foregoing, the Management Committee shall approve in advance:

     (a) the design of the System, any Joint Venture Expansion or any segment of the foregoing, and the construction, capital and operating budgets and construction fund schedules for the System, any Joint Venture Expansion or any segment of the foregoing;

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     (b) any modification to an approved budget or construction fund schedule provided for in Section 6.2 hereof;

     (c) the establishment of any requirement for Capital Contributions outside the scope and coverage of an approved budget and construction fund schedule as specified in paragraph (a) or paragraph (b) of this Section 10.4;

     (d) a Joint Venture Expansion;

     (e) the transfer by a Joint Venturer of all or any part of its Joint Venture Percentage Interest, other than as permitted without Management Committee or Joint Venturer approval pursuant to Article 12 hereof;

     (f) gas contracts and transportation agreements;

     (g) the timing and amounts of distributions to Joint Venturers pursuant to Section 8.1 hereof;

     (h) engaging in any business other than as contemplated by this Agreement;

     (i) the selection of a successor Operator;

     (j) the sale of all or substantially all of the business and assets of the Joint Venture;

     (k) any modification to the Construction and Operating Agreement; and

     (l) rules of the Management Committee and any amendments or supplements thereto concerning the conduct of the business and affairs of the Joint Venture.

     Notwithstanding anything in this Section 10.4 or elsewhere in this Agreement to the contrary, advance approval of the Management Committee shall not be required for the Operator to make any single expenditure (or series of related expenditures) less than $20,000 during any month. In addition, and notwithstanding anything herein to the contrary, in cases of emergency, the Operator may proceed with required maintenance or repair work when necessary in the Operator’s judgment to keep the System operating or to restore the facilities to operating condition or to minimize damages without prior necessity for submitting same to the Management Committee. In such event, the Operator shall as soon as practicable notify the other Joint Venturers of the existence of occurrence of the emergency, which notice shall set forth the nature of the emergency, the corrective action taken or proposed to be taken, and the estimated cost of such corrective action;

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provided that the Operator shall not be required to give such notice when the cost of the corrective action is reasonably estimated to be less than $20,000.

     10.5 Approval Requirements; Limitation on Voting Rights. Except as otherwise expressly provided by this Agreement, the business of the Joint Venture presented at any meeting of the Management Committee shall be decided by a vote of members of the Management Committee representing a majority of the Joint Venture Percentage Interests, plus one other member of the Management Committee. However, any member of the Management Committee representing a Joint Venturer who is in default in the payment of any Capital Contribution required to be made to the Joint Venture in accordance with this Agreement shall not have the right to vote on any matter unless and until such default is remedied. In addition, if an Affiliate of a Joint Venturer also owns a Joint Venture Percentage Interest, such Affiliate shall not be entitled to vote on any matter; provided, however, this limitation on the right to vote shall not apply to any Affiliate of Parallel, Capstone or Feagan. As used in this Section 10.5, “Affiliate” means a person that directly, or indirectly through one or more intermediaries, controls or is controlled by, or is under common control with, the person specified.

     10.6 Meetings. The Management Committee may hold such meetings at such place and at such time as it may determine. No notice shall be required of a regular meeting if the time and place of such meetings are fixed by the Management Committee. Notice of a special meeting shall be served not less than twenty-four (24) hours before the date and time fixed for such meeting by confirmed facsimile or other written communication or not less than three (3) days prior to such meeting if notice is provided by overnight delivery service. A special meeting of the Management Committee may be called by any Joint Venturer. Any member of the Management Committee may participate in a meeting by conference telephone or similar communications equipment. Any action required or permitted to be taken by the Management Committee may be taken without a meeting if such action is evidenced in writing and signed by the same number of members of the Management Committee required for a valid act of the Management Committee as set forth herein.

     10.7 Appointment of Operator; Construction and Operation of the System. The Joint Venturers have selected and designated Feagan as Operator of the System in accordance with the terms and conditions herein and in the Construction and Operating Agreement.

     10.8 Conduct of Operations. The Operator shall conduct all operations in a careful, diligent, prudent and workmanlike manner, but the Operator shall never be liable to any party for any acts done or omitted in good faith in the performance of any of the

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provisions of this Agreement, except for acts or omissions resulting from Operator’s gross negligence, willful misconduct, breach of fiduciary duty or breach of this Agreement.

     10.9 Expenses. Subject to the provisions hereof, the Operator shall purchase or cause to be purchased for the Joint Venture necessary materials and supplies and incur such expenses and enter into necessary commitments, including, but not limited to,

     (a) contracts for any approved additions to and replacements for the System,

     (b) contracts for power, fuel, other utilities and communications facilities as may be necessary in connection with the proper operation and maintenance of same; and

     (c) contracts for gathering of Gas for and through the System and the downstream redelivery or resale thereof.

     10.10 Personnel. Subject to the provisions hereof, the Operator shall employ such personnel as may be necessary to efficiently operate and maintain the System, all of which persons shall either be employees of the Operator or an affiliate of the Operator or independent contractors. To the extent possible, the Operator shall utilize its own employees or those of its affiliates; provided, however, that the Operator may engage the services of such independent contractors as may be necessary to carry out the terms hereof.

     10.11 Discharge of Expenses. Subject to the provisions hereof, the Operator shall promptly pay and discharge, or cause the Joint Venture to promptly pay and discharge, all expenses, costs and liabilities incurred in operating and maintaining the System, and shall be fully responsible for any liens or other encumbrances which the Operator causes or allows to be affixed or assessed against the said property and shall fully satisfy same (other than liens and encumbrances approved in advance by the Management Committee).

     10.12 Ad Valorem Taxes. The Operator shall render, or cause the Joint Venture to render, for ad valorem tax purposes, all real or personal property jointly owned hereunder, or such part thereof as may be under existing laws or may become under future laws subject to ad valorem taxation, and shall pay, or cause the Joint Venture to pay, all such taxes at the time and in the manner required by law. All taxes so paid by the Operator or the Joint Venture shall be charged to the Joint Venturers according to their respective Joint Venture Percentage Interests at the time of assessment.

     10.13 Rights of Way. The Operator shall acquire in the name of the Joint Venture the necessary rights-of-way, easements and permits required for the ownership and operation of the System and any other facilities comprising a portion thereof. To the

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extent possible, all such rights-of-way, easements and permits shall be acquired in such form as may allow assignment to the Joint Venturers. The costs of such rights-of-way, easements and permits shall be charged to the account of each of the Joint Venturers in accordance with their respective Joint Venture Percentage Interests. To the extent that any Joint Venturer (or their affiliates) has or owns rights of way, easements or other permits associated with the Project Area which may be assigned to or held on behalf of the Joint Venture such as would assist the Joint Venture in constructing, owning and operating the System, such Joint Venturer shall use its best efforts to transfer such rights to the Joint Venture and shall be reimbursed by the Joint Venture for any direct costs related thereto.

     10.14 Removal and Replacement of Operator. In addition to, but separate and apart from, the right of a Non-Defaulting Party (as defined in Section 13.4(a) hereof) to remove the Operator as a Joint Venturer from the Joint Venture pursuant to the provisions of Section 13.4 hereof, the Operator may be removed from the office of Operator (without being removed as a Joint Venturer) after written notice thereof to the Operator by any Joint Venturer in accordance with Section 9.2 of the Construction and Operating Agreement. If the Operator is removed from the office of Operator, the Management Committee (excluding the Operator) shall select a successor Operator.

ARTICLE 11
LIABILITY AND INDEMNIFICATION OF JOINT VENTURERS; INSURANCE

     11.1 Limitation of Liability of Joint Venturers. The Joint Venturers, the Management Committee, the members of the Management Committee and their respective affiliates, and their partners, officers, directors, employees and agents, shall not be liable, responsible or accountable in damages or otherwise to the Joint Venture or the other Joint Venturers for any acts or omissions that do not constitute recklessness, gross negligence, willful misconduct, a breach of fiduciary duty or a breach of the express terms of this Agreement, and the Joint Venture shall indemnify and save harmless the Joint Venturers, the Management Committee and the members of the Management Committee and their respective affiliates, and their partners, officers, directors, employees and agents (individually, “Indemnitee”) from all liabilities for which indemnification is not prohibited by the TGPL. Any act or omission performed or omitted by an Indemnitee on advice of legal counsel or a qualified independent consultant who has been employed or retained by the Joint Venture shall be presumed to have been performed or omitted in good faith without gross negligence or willful misconduct. THE PARTIES RECOGNIZE THAT THIS PROVISION SHALL RELIEVE ANY SUCH INDEMNITEE FROM ANY AND ALL LIABILITIES, OBLIGATIONS, DUTIES, CLAIMS, ACCOUNTS AND CAUSES OF ACTION WHATSOEVER ARISING OR TO ARISE OUT OF ANY ORDINARY NEGLIGENCE BY ANY SUCH

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INDEMNITEE, AND SUCH INDEMNITEE SHALL BE ENTITLED TO INDEMNIFICATION FROM ACTS OR OMISSIONS THAT MAY CONSTITUTE ORDINARY NEGLIGENCE.

     11.2 Insurance.

     (a) The Operator shall, either in its own name and for the benefit of all Joint Venturers or in the name of the Joint Venture, secure and maintain in force the policies of insurance covering the System as set out in Exhibit “D” hereto, or as may otherwise be authorized and directed by the Management Committee from time to time. The premiums for all such insurance so carried shall be paid by the Operator or the Joint Venture, as the case may be, and charged to the Joint Venturers in accordance with their respective Joint Venture Percentage Interests. Such insurance shall name each Joint Venturer as an additional assured.

     (b) Notwithstanding the foregoing, each Joint Venturer, at its own expense, shall have the right to obtain and maintain for its own account and without naming any other party as an insured, during the term of this Agreement, insurance to protect such Joint Venturer from claims. Such insurance may be for such coverages and in such amounts as each Joint Venturer shall determine.

     11.3 Claims. The administrative responsibility for handling claims, whether or not covered by insurance carried by the Operator or the Joint Venture, and the administrative responsibility for handling litigation, including the employment of attorneys for the System, shall, but only with the unanimous concurrence of the Joint Venturers parties hereto, belong to the Operator; provided, however, that any Joint Venturer may have counsel of its own choice to defend its own interest. Each Joint Venturer who receives any claim or demand shall promptly give notice of same to the Operator and provide the Operator full and complete information with respect thereto. The Operator shall promptly give each other Joint Venturer written notice of any such claim or demand. The Operator may not settle any losses, damages and claims, whether or not covered by insurance, without the prior written consent of all Joint Venturers.

     All costs of handling, settling or otherwise discharging such claim or suit shall be charged to the Joint Venturers according to their respective Joint Venture Percentage Interests. The Operator shall at any time requested furnish any Joint Venturer with full information concerning the kind, character and amounts of insurance carried. The Operator shall promptly notify the Joint Venturers of any loss, damage or claim not covered by insurance carried by the Operator or the Joint Venture and of any loss, damage or claim that might be considered or assumed to be in excess of the insurance coverage provided by the Operator or the Joint Venture for the benefit of the Joint Venturers.

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     11.4 Contractors and Subcontractors. The Operator shall require its contractors and subcontractors conducting operations on the System to carry insurance of the types set out above and in the amounts applicable to the contractor’s and subcontractor’s operations, and such other insurance in amounts deemed adequate by the Operator for any particular contract. The Operator shall require all contractors employed as provided herein, insofar as possible, to indemnify and hold the Operator and the other Joint Venturers hereto harmless from and against all claims, demands or causes of action arising out of the performance of contractor’s work.

ARTICLE 12
ASSIGNMENTS

     12.1 Limitation of Right to Transfer Joint Venturers’ Interests. Each Joint Venturer may sell, assign or otherwise transfer in any manner all or any part of its Joint Venture Percentage Interest in the Joint Venture and in this Agreement without the consent of the Management Committee or the other Joint Venturers, but the other Joint Venturers shall have a right, but not the obligation, to sell, assign or transfer a like percentage of their respective Joint Venture Percentage Interests on the same terms which the transferring Joint Venturer proposes to sell, assign or otherwise transfer; provided, however, a merger, consolidation, reorganization or other acquisition of a Joint Venturer shall not be deemed to be a sale, assignment or transfer of a Joint Venture Percentage Interest for purposes of this Section 12.1. In such event, the transferring Joint Venturer shall promptly give written notice to the other Joint Venturers of its desire to sell, assign or otherwise transfer its Joint Venture Percentage Interest, furnishing full information concerning the proposed sale, assignment or transfer, including the name and address of the prospective transferee (who shall be ready, willing and able to comply with all terms of the proposed sale, assignment or transfer), the purchase price and other consideration, and all terms of the offer made by the prospective transferee. Each non-transferring Joint Venturer shall then have an optional prior right, for a period of fifteen (15) days after its receipt of notice from the transferring Joint Venturer, to accept in writing and sell, assign or transfer a like percentage of its Joint Venture Percentage Interest upon the same terms and conditions which the transferring Joint Venturer proposes to sell, assign or otherwise transfer its Joint Venture Percentage Interest. Upon completion of the sale, assignment or transfer of a Joint Venturer’s Joint Venture Percentage Interest pursuant to this Section 12.1, the transferee shall be admitted as a Joint Venturer. Notwithstanding any other provision of this Section 12.1, no Joint Venture Percentage Interest or other interest in the profits and losses of the Joint Venture may be transferred if such transfer would result in the Joint Venture or any Joint Venturer becoming subject to the Public Utility Holding Company Act of 1935. In addition, and notwithstanding anything herein to the contrary, the provisions of this Section 12.1 shall not apply to the transfer or pledge of an interest in the Joint Venture made pursuant to Section 12.2 below.

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     12.2 Permitted Transfers by Joint Venturers. Subject to the penultimate sentence of Section 12.1, nothing in this Agreement shall prevent or require the consent of any Joint Venturer for:

     (a) the transfer at any time by any Joint Venturer of all its right, title and interest in the Joint Venture (including indebtedness thereof) and in this Agreement if all of such right, title and interest is transferred to another Person by merger, reorganization, consolidation or sale of all or substantially all of its assets, or a sale or transfer of the stock or other voting securities of such Joint Venturer, or the sale or transfer of the interest in the Joint Venture to a subsidiary or parent company, or a subsidiary of a parent company, or to any company in which the transferring Joint Venturer (or an affiliate) owns a majority of the voting securities; provided that the transferee assumes by operation of law or express agreement with the Joint Venture (in form and substance reasonably satisfactory to the other Joint Venturers) all of the obligations of the transferor under this Agreement and that no such transfer (other than pursuant to a merger, reorganization, consolidation or other combination wherein all obligations and liabilities of the Joint Venturer are assumed by the successor by operation of law) shall relieve the transferor of its obligations under this Agreement without the written approval of the other Joint Venturers, and provided, further, that upon such transfer the transferee shall be admitted as a Joint Venturer in substitution of the Joint Venturer which was the transferor; or

     (b) an assignment, pledge or other transfer at any time creating a security interest (and any transfer made in foreclosure or other enforcement of such security interest) in all or any portion of a Joint Venturer’s interest in or distributions from the Joint Venture (as opposed to a pledge or mortgage of Joint Venture property) under any pledge or other security agreement created by any Joint Venturer; provided, however, that such assignee, pledgee, or secured party (i) shall hold the same subject to all the terms of this Agreement and (ii) shall not have any voice in the management of the Joint Venture as a result of any such assignment, pledge or other transfer.

     12.3 Effect of Permitted Transfers. No assignment, pledge or other transfer pursuant to Section 12.2 shall give rise to a right in any Joint Venturer to wind up the Joint Venture. Except as provided in Section 12.1 and in Section 12.2(a), no assignment, pledge or other transfer shall give rise to a right in any transferee to become a Joint Venturer in the Joint Venture, unless approved by the Management Committee.

     12.4 Effects of Prohibited Transfers. Any transfer or attempted transfer of an interest in the Joint Venture by a Joint Venturer in violation of the terms of this Agreement shall be void ab initio and shall not bind or be recognized by the Joint Venture or the Joint Venturers.

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ARTICLE 13
TERM; TERMINATION AND WINDING UP

     13.1 Term. The Joint Venture shall be in effect for a term beginning on the date of this Agreement and shall continue until terminated and wound up in accordance with the provisions hereof. All provisions of this Agreement relative to termination and winding up shall be cumulative; that is, the exercise or use of one of the provisions hereof shall not, unless the context requires, preclude the exercise or use of any other provision hereof.

     13.2 Voluntary Withdrawal of a Joint Venturer. Any Joint Venturer shall have the right to withdraw from the Joint Venture on the last day of any fiscal year of the Joint Venture by giving the other Joint Venturers written notice of intent to withdraw. Such notice shall be given not less than 60 days prior to the last day of any fiscal year.

     13.3 Automatic Termination.

(a) If any of the following shall occur:

(1)	the Joint Venturers agree unanimously in writing to terminate and wind up the Joint Venture; or
(2)	an event which makes it unlawful for the business of the Joint Venture to be carried on; or
(3)	the sale or abandonment of all or substantially all of the Joint Venture’s business and assets; or
(4)	the tenth anniversary of the date of this Agreement;

then the Joint Venture and its business shall be promptly wound up, terminated and liquidated.

(b) If any of the following events of withdrawal shall occur:

(1)	the voluntary withdrawal of a Joint Venturer in accordance with Section 13.2; or
(2)	the commencement by any Joint Venturer of a voluntary case under the federal bankruptcy laws, as now constituted or hereafter amended, or any other applicable federal or state bankruptcy, insolvency or other similar law, or the consent by any Joint Venturer to, or acquiescence in, the appointment of or taking possession by a

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	receiver, liquidator, assignee, trustee, custodian, sequestrator (or other similar official) of said Joint Venturer or for all or any substantial part of its property or its interest in the Joint Venture (the term “acquiescence” being deemed to include, but not limited to, the failure to file a petition or motion to vacate or discharge any order, judgment or decree providing for such appointment within ten (10) days after the appointment); or
(3)	the entry of a decree or order for relief by a court having jurisdiction in the premises in respect of any Joint Venturer in an involuntary case under the federal bankruptcy laws, as now or hereafter constituted, or any other applicable federal or state bankruptcy, insolvency, or other similar law, or appointing a receiver, liquidator, assignee, custodian trustee, sequestrator (or similar official) of the Joint Venturer or for any substantial part of its property or its interest in the Joint Venture, or ordering the winding up or liquidation of the affairs of said Joint Venturer, and said Joint Venturer shall acquiesce in the entry of such decree or order (the term “acquiesce” being deemed to include, but not limited to, the failure to file a petition or motion to vacate such order or decree within ten (10) days of the entry thereof) or any such order or decree shall continue unstayed and unvacated for a period of sixty (60) consecutive days from the date of entry thereof; or
(4)	the failure or inability of any Joint Venturer generally to pay its debts as such debts become due; or
(5)	any Joint Venturer shall give notice to any governmental body of insolvency or pending insolvency, or suspension or pending suspension of operations; or
(6)	any Joint Venturer shall make an assignment for the benefit of creditors or take any other similar action for the protection or benefit of creditors; or

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(7)	any Joint Venturer shall sell or otherwise dispose of all or substantially all of its assets (other than by reason of a transaction described in Section 12.2(a)); or
(8)	any Joint Venturer shall take any action in furtherance or confirmation of the events mentioned in (2) through (7) above; or
(9)	the death of any Joint Venturer; or
(10)	the removal of a Joint Venturer from the Joint Venture in accordance with Section 13.4,

then the Joint Venture and its business shall be promptly wound up, terminated and liquidated and:

(i)	the Joint Venturer as to whom an event described above has occurred (the “Withdrawing Party”) shall immediately cease to be a Joint Venturer; and
(ii)	the Joint Venture and its business shall be wound up and terminated, unless the remaining Joint Venturers (the “Non-Withdrawing Parties”) shall elect unanimously in writing to continue the business of the Joint Venture.

     13.4 Removal for Default.

     (a) If any Joint Venturer fails to observe or perform any of its obligations, covenants or agreements hereunder or set forth herein, then in such event, any other Joint Venturer (“Non-Defaulting Party”) shall have the right to give such party (“Defaulting Party”) a notice of default (“Notice of Default”). The Notice of Default shall set forth the nature of the obligation which the Defaulting Party has not observed or performed.

     (b) If within the thirty (30) day period following receipt of the Notice of Default, the Defaulting Party in good faith commences to perform such obligation and cure such default and thereafter prosecutes to completion with diligence and continuity the curing thereof and cures such default within a reasonable time, it shall be deemed that the Notice of Default was not given and the Defaulting Party shall lose no rights hereunder. If, within such thirty (30) day period, the Defaulting Party does not commence in good faith the curing of such default or does not thereafter prosecute to completion with diligence and continuity the curing thereof, any Non-Defaulting Party shall have the right to remove the Defaulting Party from the Joint Venture by giving the Defaulting Party and all other Joint Venturers written notice thereof.

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     (c) The foregoing cure provisions of this Section 13.4 shall not apply to any default with respect to the payment of any sums of money by or to any Joint Venturer, which sums of money shall be paid within thirty (30) days after receipt of a Notice of Default with respect thereto. If such sums are not so paid within such thirty (30) day period, any Non-Defaulting Party shall have the right to remove the Defaulting Party from the Joint Venture by giving the Defaulting Party and all other Joint Venturers written notice thereof.

     13.5 Remedies of Non-Withdrawing Party.

     (a) If the Non-Withdrawing Parties continue the business of the Joint Venture as contemplated by Section 13.3(b)(ii) hereof, they shall promptly institute the procedures set forth in Section 13.6 hereof (the “Buy-Sell Procedures”).

     (b) The rights of a Non-Withdrawing Party under this Article 13 shall not be the exclusive remedies of the Non-Withdrawing Party, except in the case of a voluntary termination under Section 13.2, but shall be in addition to all other rights and remedies, if any, available to the Non-Withdrawing Party at law or in equity.

     13.6 Buy-Sell Procedures.

     (a) Upon the event specified in Section 13.5(a), the Non-Withdrawing Party(s) shall give written notice of the institution of the Buy-Sell Procedures to the Withdrawing Party within thirty (30) days after the event specified in Section 13.3(b). Within thirty (30) days after receipt of such notice, the Withdrawing Party shall deliver to each Non-Withdrawing Party an offer (“Offer”) in writing, stating the cash purchase price under which the Withdrawing Party is willing to purchase the interest in the Joint Venture of each Non-Withdrawing Party. Such price shall be stated in terms of the price attributable to 100% of the Joint Venture. The Non-Withdrawing Party(s) then shall be obligated either to elect:

(1) to purchase the interest of the Withdrawing Party in the Joint Venture for cash at a price equal to the 100% price stated in the Offer multiplied by the Withdrawing Party’s Joint Venture Percentage Interest (in the event that more than one Non-Withdrawing Party elects to purchase the interest of a Withdrawing Party hereunder, then each Non-Withdrawing Party so electing shall purchase a fraction of the Withdrawing Party’s Joint Venture ownership interest equal to that Non-Withdrawing Party’s interest in the Joint Venture divided by the interest of all Non-Withdrawing Parties in the Joint Venture electing to purchase the interest of the Withdrawing Party); or

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(2) to sell to the Withdrawing Party the interest of the Non-Withdrawing Party in the Joint Venture for cash at a price equal to the 100% price stated in the Offer multiplied by the Non-Withdrawing Party’s Joint Venture Percentage Interest.

The Non-Withdrawing Parties shall exchange written notices with all other Non-Withdrawing Parties of such election within thirty (30) days after receipt of the Offer. After receipt of any notice from another Non-Withdrawing Party, a Non-Withdrawing Party may change its election but must notify all other Non-Withdrawing Parties in writing of its change prior to notifying the Withdrawing Party. After final notification to all other Non-Withdrawing Parties, but not later than one hundred eighty (180) days after receipt of the Offer, a Non-Withdrawing Party shall give written notice of its election to the Withdrawing Party. Failure of the Non-Withdrawing Party to give all Non-Withdrawing and Withdrawing Parties notice that the Non-Withdrawing Party has elected under Subsection (1) above shall be conclusively deemed to be an election under Subsection (2) above.

     (b) The closing of a purchase pursuant hereto shall be held at a mutually acceptable place on a mutually acceptable date not more than thirty (30) days after receipt by the Withdrawing Party of the written notice of all Non-Withdrawing Parties’ election under Section 13.6(a) hereof. At such closing, the selling party shall assign to the purchasing party the interest in the Joint Venture so sold free and clear of all liens, claims, and encumbrances and, at the request of the purchasing party, in order to properly set forth the record title to the assets of the Joint Venture, shall convey and transfer to the purchasing party, with covenants of special warranty, an undivided percentage interest in the assets of the Joint Venture owned by it and execute all other documents that may be necessary to effectuate the purpose of this Agreement and the purchasing party shall pay the purchase price therefor in cash or by a cashier’s or certified check from a bank acceptable to the selling party. The purchasing party shall assume the obligations of the selling party under this Agreement and under the Joint Venture. As a condition for purchase, the seller may demand, and shall be entitled, to be indemnified by the Joint Venture from and against any and all obligations, costs, or expense relating to or arising under any financing agreement to which the Joint Venture is a party.

     (c) If the Withdrawing Party fails to make an Offer pursuant to Section 13.6(a) hereof, or if either the Withdrawing Party or Non-Withdrawing Party elects pursuant to Section 13.6(a), but thereafter does not close the purchase of such interest pursuant hereto, then the party so failing shall be deemed to be a non-performing party (“Non-Performing Party”) and the other party (“Electing Party”), in addition to its other rights and remedies, may (1) continue the Joint Venture, (2) purchase the interest in the Joint Venture of the Non-Performing Party at the purchase price determined by multiplying the Non-Performing Party’s Joint Venture Percentage Interest by the purchase price

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attributable to 100% of the Joint Venture as set forth in the Offer (if one was so made), or (3) purchase the interest in the Joint Venture of the Non-Performing Party pursuant to Section 13.7.

     13.7 Appraisal Procedure.

     (a) If an election is made under Section 13.6(c) to proceed under this Section 13.7 to purchase the interest of the Non-Performing Party in and to the Joint Venture at the Appraised Value (hereinafter defined) thereof, the Electing Party shall give the Non-Performing Party written notice thereof within thirty (30) days after such default, and in such notice shall designate the first appraiser (“First Appraiser”).

     (b) Within fifteen (15) days after the service of notice referred to in Section 13.7(a) hereof, the Non-Performing Party shall give written notice to the Electing Party designating the second appraiser (“Second Appraiser”). If the Non-Performing Party fails to designate the Second Appraiser within ten (10) days, then the Electing Party shall designate the Second Appraiser. The First and Second Appraisers so designated shall meet within ten (10) days after the Second Appraiser is appointed and if, within thirty (30) days after the Second Appraiser is appointed, the First and Second Appraisers do not agree upon Appraised Value, they shall, within fifteen (15) days, appoint a third appraiser (“Third Appraiser”). In the event of the failure or inability of the First and Second Appraisers to appoint a Third Appraiser within such fifteen (15) day period, then the Electing Party shall designate the Third Appraiser. In the event of the failure, refusal or inability of any appraiser to act, a new appraiser shall be appointed in his stead, which appointment shall be made by the party that initially designated such appraiser so failing, refusing or being unable to act. Each party shall pay an equal share of the fees and expenses of the appraisers. Any appraiser designated to serve in accordance with the provisions of this Agreement shall be disinterested and shall be qualified to appraise property of the type owned by the Joint Venture.

     (c) The appraisers shall determine the value of one hundred percent (100%) of the Joint Venture, which shall be the amount by which the fair market value, at the time such appraisal is made, of all the assets of the Joint Venture exceeds all liabilities of the Joint Venture, including, but not limited to, liabilities for the repayment of all loans to the Joint Venture (“Appraised Value”). If the First Appraiser and the Second Appraiser do

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not agree upon the Appraised Value within the thirty (30) day period set forth above, the Third Appraiser shall determine the Appraised Value of the Joint Venture within thirty (30) days after his appointment. In such event, the Appraised Value of the Joint Venture for purposes of this Agreement shall be the value determined by the First Appraiser or the Second Appraiser which is closest to the Appraised Value determined by the Third Appraiser; provided, however, that if the Appraised Values of the First and Second Appraisers differ from the Appraised Value established by the Third Appraiser by the same amount, the Appraised Value established by the Third Appraiser shall be the Appraised Value of the Joint Venture for purposes of this Agreement. After reaching a decision, the appraisers shall give written notice thereof to all the Joint Venturers.

     (d) The Electing Party may purchase the Non-Performing Party’s interest in the Joint Venture for a cash price equal to the Appraised Value multiplied by the Joint Venture Percentage Interest of the Non-Performing Party. The closing of such purchase shall occur at a mutually acceptable time within thirty (30) days after notice of the decision of the appraisers has been delivered to the Joint Venturers, and otherwise shall be conducted in accordance with Section 13.6(b) hereof.

     (e) If the appraisers fail to reach a decision within ninety (90) days after the appointment of the Third Appraiser, the Electing Party shall have the right to withdraw its election to purchase the Withdrawing Party’s interest in the Joint Venture pursuant to this Section 13.7.

     13.8 Termination and Winding Up.

     (a) As expeditiously as possible following the occurrence of an event giving rise to a termination and winding up of the Joint Venture pursuant to the terms hereof, the Management Committee shall designate a “Liquidating Trustee” who shall promptly proceed to wind up and terminate the business and affairs of the Joint Venture. Subject to the direction and control of the Management Committee, the Liquidating Trustee shall have such powers as may be necessary during the period of winding up to continue operating the System in the normal course to the extent appropriate for the purpose of winding up the business and affairs of the Joint Venture and liquidating the assets thereof in an orderly manner, but the Joint Venture shall not engage in any new business during the period of winding up. In winding up the Joint Venture, the Liquidating Trustee shall distribute the assets of the Joint Venture as described below:

(i) debts of the Joint Venture, other than to the Joint Venturers, shall be paid (or adequate provision shall be made for the payment thereof); then

(ii) debts owed by the Joint Venture to the Joint Venturers shall be paid; then

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(iii) all remaining assets of the Joint Venture shall be distributed to the Joint Venturers as follows:

(1)	all cash on hand representing unexpended Capital Contributions by any Joint Venturer shall be returned to the contributor, then
(2)	the Liquidating Trustee may sell any or all Joint Venture property and any resulting gain or loss from each sale shall be computed and allocated to the capital accounts of the Joint Venturers as provided in Section 7.1;
(3)	with respect to all Joint Venture property that has not been sold, the fair market value of that property shall be determined and the capital accounts of the Joint Venturers shall be adjusted to reflect the manner in which the unrealized income, gain, loss, and deduction inherent in property that has not been reflected in the capital accounts previously would be allocated among the Joint Venturers under Section 7.1 if there were a taxable disposition of that property for the fair market value of that property on the date of distribution; and
(4)	Joint Venture property shall be distributed among the Joint Venturers in the amounts specified in Section 8.1.

All distributions in kind to the Joint Venturers shall be valued for purposes of determining each Joint Venturer’s interest therein at its fair market value at the time of such distribution, and such distributions shall be made subject to the liability of each distributee for costs, expenses, and liabilities theretofore incurred or for which the Joint Venture has committed prior to the date of termination, and those costs, expenses, and liabilities shall be allocated to the distributee pursuant to this Section 13.8. It is intended that the foregoing distributions to each Joint Venturer will be equal to each Joint Venturer’s respective positive capital account balance as determined after giving effect to the foregoing adjustments and to all adjustments attributable to allocations of items of income, gain, loss and deduction realized by the Joint Venture during the taxable year in question and all adjustments attributable to contributions and distributions of money and property effected prior to such distribution. To the extent that any such Joint Venturer’s positive capital account balance does not correspond to such distribution, the allocations provided for in Section 7.1 shall be adjusted, to the least extent necessary, to produce a capital account balance for the Joint Venturer which corresponds to the amount of such distribution. Any distribution to the Joint Venturers in liquidation of the Joint Venture shall be made by the later of the end of the taxable year in which the liquidation occurs or 90 days after the date of such liquidation. For purposes of the preceding sentence, the

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term “liquidation” shall have the same meaning as set forth in Treasury Regulation §1.704-1(b)(2)(ii). The distribution of cash and/or property to a Joint Venturer in accordance with the provisions of this Section 13.8 constitutes a complete return to the Joint Venturer of its Capital Contribution and a complete distribution to the Joint Venturers of its Joint Venture Percentage Interest and all the Joint Venture’s property and constitutes a compromise to which all Joint Venturers have consented. To the extent that a Joint Venturer returns funds to the Joint Venture, it has no claim against any other Joint Venturer for those funds.

     (b) Notwithstanding anything to the contrary contained in this Agreement, and notwithstanding any custom or rule of law to the contrary, no Joint Venturer shall be obligated to restore a deficit balance in its capital account at any time.

     (c) All assignments under this Section 13.8 shall be by special warranty. Such assignments shall be made subject to the liability of each assignee for costs, expenses and liabilities theretofore incurred or for which a commitment has been made by the Joint Venture prior to the date of termination, and such costs, expenses and liabilities shall be allocated to such assignee pursuant to this Agreement.

     13.9 Effect of Termination or Withdrawal. No termination of the Joint Venture shall relieve a Joint Venturer from any obligation accruing or accrued to the date of such termination or deprive a Joint Venturer not in default hereunder of any remedy otherwise available to it. Withdrawal by a Joint Venturer pursuant to Section 13.3(b) shall terminate such Withdrawing Joint Venturer’s status as a Joint Venturer, forfeit its voting rights in Joint Venture affairs and terminate its representation on the Management Committee. In addition, a Joint Venturer’s withdrawal shall not affect any obligations or liabilities incurred by such Joint Venturer prior to withdrawal, nor shall such withdrawal affect any other Joint Venturer’s right to seek damages that it may have incurred as a result of such withdrawal.

ARTICLE 14
SALVAGE

     14.1 Abandonment. It is agreed that, upon abandonment of the System or any portion thereof, the cost of the salvage of the line so abandoned shall be borne by the Joint Venturers in accordance with their respective Joint Venture Percentage Interests. Credits derived from salvaged material shall be distributed to the Joint Venturers in accordance with their respective Joint Venture Percentage Interests. If the cost of salvage is more than the credits possible of being received therefrom, salvage operations shall be limited to those required by the governmental regulations then in effect and applicable to the System.

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ARTICLE 15
CONFIDENTIALITY

     15.1 Confidentiality. Except as may be required or advisable under applicable law or valid subpoena or other lawful process or other regulatory requirements, each Joint Venturer agrees that it will (consistent with its reasonable practices and procedures adopted in good faith for handling confidential information) keep confidential all Joint Venture information relating to the Joint Venture’s properties and assets, and the Joint Venture’s financial information, and will not disclose any such information to any Person whatsoever (other than such Joint Venturer’s officers, directors, employees, beneficial owners, attorneys, accountants, advisors or potential transferees (provided each of such Persons is informed of the confidential nature of such information) or to another Joint Venturer and its representatives); provided, however, that the foregoing covenant of each Joint Venturer shall not apply to any information that (a) was or becomes generally available to the public other than as a result of disclosure by such Joint Venturer, (b) becomes available to such Joint Venturer from a source other than the Joint Venture, provided that such source is not (to the knowledge of such Joint Venturer) bound by a confidentiality agreement with the Joint Venture, (c) such Joint Venturer can establish was within its possession prior to it being furnished to such Joint Venturer by or on behalf of the Joint Venture, provided that the source of such information was not (to the knowledge of such Joint Venturer) bound by a confidentiality agreement with the Joint Venture in respect thereof, or (d) is necessary to be made in connection with any financing or investment activity permitted by this Agreement.

ARTICLE 16
MISCELLANEOUS

     16.1 Notice. Any notice, request or other communication required by this Agreement shall be in writing and shall be deemed to have been given on the third day following the day of mailing, if the same shall be mailed by certified or registered mail, return receipt requested, postage prepaid, addressed to:

     (a) each Joint Venturer at the address designated from time to time by such Joint Venturer by written notice to the Joint Venture, and

     (b) the Joint Venture at its principal office specified in Section 3.2 or such other address as may be designated from time to time by written notice to each of the Joint Venturers.

     Until changed by notice pursuant hereto, the address of each party for purposes of this Agreement is as follows:

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Parallel Petroleum Corporation
1004 N. Big Spring, Suite 400
Midland, Texas 79701
Attn: John S. Rutherford

Feagan Gathering Company
130 Spring Park Drive, Suite 105
Midland, Texas 79705
Attn: Joe Feagan

Capstone Oil & Gas Company, L.P.
P.O. Box 10187
Midland, Texas 79702
Attn: Dale Douglas

     16.2 Further Assurance. Each of the Joint Venturers agrees to execute and deliver all such other and additional instruments and documents and to do such other acts and things as may be reasonably necessary to effectuate this Agreement and the Joint Venture created thereby and to carry on the business of the Joint Venture in accordance with this Agreement.

     16.3 Amendment This Agreement may be amended, supplemented or restated only with the written consent of all the Joint Venturers.

     16.4 Waiver. No waiver by any Joint Venturer or any default by any other Joint Venturer in the performance of any provision, condition or requirement herein shall be deemed to be a waiver of, or in any manner release the other Joint Venturers from performance of any other provision, condition or requirement herein; nor deemed to be a waiver of, or in any manner a release of the other Joint Venturers from future performance of the same provision, condition or requirement. Any delay or omission of any Joint Venturer to exercise any right hereunder shall not impair the exercise of any such right, or any like right, accruing to it thereafter. No waiver of a right created by this Agreement by one Joint Venturer shall constitute a waiver of such right by the other Joint Venturers except as may otherwise be hereto.

     16.5 Exhibits. The exhibits, annexes and schedules attached to this Agreement are incorporated herein and shall be considered a part of this Agreement for the purposes stated herein, except that in the event of any conflict between any of the provisions of such exhibits, annexes and schedules and the provisions of this Agreement, the provisions of this Agreement shall prevail; provided, however, the fact that any term, condition or covenant contained in such exhibits, annexes and schedules is not contained herein shall not be, or be deemed to be, a conflict. All capitalized terms used in such exhibits, annexes

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and schedules, but not defined therein, shall have the same meanings as given to such terms in this Agreement.

     16.6 Applicable Laws. This Agreement shall be governed by and interpreted in accordance with the laws of the State of Texas.

     16.7 Counterparts This Agreement may be executed in any number of separate counterparts, each of which shall be deemed an original, but all of which taken together shall constitute one and the same instrument.

     16.8 Headings. The headings contained in this Agreement are for reference purposes only and shall not affect the meaning or interpretation of this Agreement.

     16.9 Entirety. As to matters covered by this Agreement, this Agreement constitutes the entire agreement of the parties hereto and is the complete and final expression of such agreement.

     16.10 Severability. If one or more of the provisions contained herein shall, for any reason, be held invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Agreement.

     16.11 Binding Effect; Joinder of Additional Parties. Subject to the restrictions on dispositions and transfers set forth herein, this Agreement shall be binding upon and shall inure to the benefit of the Joint Venturers parties hereto, as well as their respective heirs, legal representatives, successors and assigns.

     16.12 Third Party Beneficiaries. Except as otherwise provided in Article 11, it is the intent of the Joint Venturers parties hereto that no third-party beneficiary rights be created or deemed to exist in favor of any Person not a party to this Agreement, unless otherwise expressly agreed to in writing by the Joint Venturers.

ARTICLE 17
ARBITRATION

     17.1 General. The Joint Venturers acknowledge and agree that any claim or controversy arising out of or relating to this Agreement, or the breach of this Agreement, or any other dispute arising out of or relating to the relationships among the Joint Venturers, shall be settled by final and binding arbitration in the City of Midland, Texas in accordance with the Expedited Procedures and Commercial Arbitration Rules of the American Arbitration Association in effect on the date the claim or controversy arises.

     17.2 Procedures. Any arbitration called for by this Article 17 shall be conducted in accordance with the following procedures:

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     (a) The Joint Venture or any Joint Venturer (the “Requesting Party”) may demand arbitration at any time by giving written notice of such demand (the “Demand Notice”) to all other Joint Venturers and (if the Requesting Party is not the Joint Venture) to the Joint Venture, which Demand Notice shall describe in reasonable detail the nature of the claim, dispute or controversy.

     (b) Within 15 days after the giving of a Demand Notice, the Requesting Party, on the one hand, and each of the other Joint Venturers and/or the Joint Venture against whom the claim has been made or with respect to which a dispute has arisen (collectively, the “Responding Party”), on the other hand, shall together select and designate in writing to the other party one reputable, disinterested individual (a “Qualified Individual”), willing to act as an arbitrator of the claim, dispute or controversy in question. Each of the Requesting Party and the Responding Party shall use their best efforts to select an arbitrator licensed to practice law in the State of Texas and having no affiliation with any of the parties as their respective Qualified Individual. Within 15 days after the foregoing selections have been made, the arbitrators so selected shall jointly select an arbitrator licensed to practice law in the State of Texas having no affiliation with any of the parties as the third Qualified Individual willing to act as an arbitrator of the claim, dispute or controversy in question. If the two arbitrators initially selected are unable to agree on a third arbitrator within the second 15-day period referred to above, then, on the application of either party, the American Arbitration Association shall promptly select and appoint an arbitrator licensed to practice law in the State of Texas having no affiliation with any of the parties as the Qualified Individual to act as the third arbitrator. The three arbitrators selected pursuant to this subsection (b) shall constitute the arbitration panel for the arbitration in question.

     (c) The presentations of the parties hereto in the arbitration proceeding shall be commenced and completed within 60 days after the selection of the arbitration panel pursuant to subsection (b) above, and the arbitration panel shall render its decision in writing within 30 days after the completion of such presentations. Any decision concurred in by any two of the arbitrators shall constitute the decision of the arbitration panel, and unanimity shall not be required.

     (d) The arbitration panel shall have the discretion to include in its decision a direction that all or part of the attorneys’ fees and costs of any party or parties and/or the costs of such arbitration be paid by any other party or parties. On the application of a party before or after the initial decision of the arbitration panel, and proof of its attorneys’ fees and costs, the arbitration panel shall order the other party to make any payments directed pursuant to the preceding sentence.

     (e) Any decision rendered by the arbitration panel shall be final and binding on the parties hereto, and judgment thereon may be entered by any state or federal court of competent jurisdiction.

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     (f) Arbitration shall be the exclusive method available for resolution of claims, disputes and controversies described in Section 17.1, and the Joint Venture and its Joint Venturers stipulate that the provisions hereof shall be a complete defense to any suit, action, proceeding in any court or before any administrative or arbitration tribunal with respect to any such claim, controversy or dispute. The provisions of this Article 17 shall survive the dissolution of the Joint Venture.

     (g) Nothing contained herein shall be deemed to give the arbitrators any authority, power or right to alter, change, amend, modify, add to or subtract from any of the provisions of this Agreement.

     17.3 Specific Enforcement. The Joint Venturers acknowledge and agree that the arbitration provisions in Sections 17.1 and 17.2 may be specifically enforced by any Joint Venturer, and submission to arbitration proceedings compelled, by any court of competent jurisdiction. The Joint Venturers further acknowledge and agree that the decision of the arbitrators may be specifically enforced by any Joint Venturer in any court of competent jurisdiction.

[Remainder of page left blank intentionally]

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     IN WITNESS WHEREOF, each of the parties hereto has caused this Agreement to be executed by its respective duly authorized officer as of the date first written above, to be effective from and after April 1, 2006.

FEAGAN GATHERING COMPANY
By:	/s/ Mike Feagan
	Mike Feagan, President
PARALLEL PETROLEUM CORPORATION
By:	/s/ John S. Rutherford
	John S. Rutherford, Vice President of
	Land and Administration
CAPSTONE OIL & GAS COMPANY, L.P. By:  Capstone Investments, Inc., its           general partner
By:	/s/ Dale Douglas
	Dale Douglas, President

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Exhibit “A”
to
Joint Venture Agreement

CONSTRUCTION AND OPERATING AGREEMENT

     This Construction and Operating Agreement, dated as of January 16, 2007, to be effective from and after April 1, 2006, is between Hagerman Gas Gathering System, a joint venture organized under the laws of Texas (the “Joint Venture”), and Feagan Gathering Company, a Texas corporation (the “Operator”).

WITNESSETH:

     Whereas, the Joint Venture has been formed by Parallel Petroleum Corporation, a Delaware corporation, Capstone Oil & Gas Company, L.P., a Texas limited partnership, and Feagan Gathering Company, a Texas corporation (collectively, the “Joint Venturers,” and individually, a “Joint Venturer”) pursuant to that certain Joint Venture Agreement, dated as of January 16, 2007, among the Joint Venturers; and

     Whereas, Operator is engaged in the business of designing and constructing facilities of the nature as that desired by the Joint Venture, and Operator represents that it has at this time an adequate, competent and fully-trained organization together with access to necessary tools, machinery and equipment with which it desires to perform such work for the Joint Venture; and

     Whereas, Feagan Gathering Company has been designated as Operator of a pipeline and appurtenant facilities owned or to be owned by the Joint Venture and located in Chaves County, New Mexico; and

     Whereas, Operator and the Joint Venture desire to enter into this Agreement for the work to be done under the terms and conditions as hereinafter provided.

     NOW, THEREFORE, for and in consideration of the mutual covenants and agreements herein contained to be done, paid and performed, Operator and the Joint Venture agree as follows:

ARTICLE 1
Definitions

          1.1 Defined Terms.

          (a) Capitalized terms used herein which are defined in the Joint Venture Agreement and not otherwise defined herein shall have the meanings specified in the Joint Venture Agreement.

          (b) The words “hereof”, “herein” and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement.

          (c) In addition to the terms defined in the preamble and the recitals of this Agreement, and in the Joint Venture Agreement, the following terms shall have the following meanings:

          “Agreement” means this Construction and Operating Agreement, as the same may be amended from time to time.

          “Joint Venture Agreement” means that certain Joint Venture Agreement, dated as of January 16, 2007, by and among Parallel Petroleum Corporation, Capstone Oil & Gas Company, L.P. and Feagan Gathering Company, as the same may be amended from time to time.

ARTICLE 2
Operator

          2.1 Designation of Operator. In accordance with Section 10.2 and Section 10.7 of the Joint Venture Agreement, Feagan has been designated as Operator of the System.

          2.2 Duties of Operator. In addition to the duties of the Operator as set forth in the Joint Venture Agreement, Operator shall recommend the design, construction, operation, maintenance, replacement, removal and improvement of the System and shall do and perform, for and on behalf of the Joint Venture, any and all acts and things necessary, requisite or proper in connection therewith or in carrying out Operator’s duties and obligations pursuant to the directions of the Management Committee.

          2.3 Reports. Operator shall report to the Management Committee on all matters pertaining to the planning, design, construction and operation of the System. During the construction of the System, Operator shall report to the Management Committee not less frequently than one time each week. After the construction of the

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System, and throughout the operation of the System, Operator shall report to the Management Committee not less frequently than one time each month.

          2.4 Limitations. The rights, duties, obligations and responsibilities of Operator under this Agreement shall be subject in all respects to the provisions of the Joint Venture Agreement as they relate to Operator.

ARTICLE 3
Conduct of Operations

          3.1 Standard of Care. Operator shall perform its services and carry out its responsibilities under this Agreement (i) in accordance with the standards set forth in the Joint Venture Agreement, (ii) in accordance with all applicable laws, rules, orders and regulations of governmental authorities and (iii) with due diligence and in accordance with engineering practices customarily accepted for work similar to that contemplated by this Agreement. In performing its duties and obligations under this Agreement, Operator shall act fairly and impartially, and shall not favor any one Joint Venturer and shall act as an independent contractor and not an employee or agent of the Joint Venture or the Joint Venturers.

          3.2 Turnover of Property. If Operator receives any monies or other property properly owing or belonging to the Joint Venture or any Joint Venturer, such monies or other property shall be delivered forthwith by Operator to the Joint Venture or Joint Venturer, as the case may be, in the form received, except for the addition of any endorsement or assignment necessary to effect a transfer of all rights therein to the Joint Venture or Joint Venturer. The Joint Venture and each Joint Venturer is irrevocably authorized to supply any required endorsement or assignment which may have been omitted. Until so delivered, any such monies or other property shall be held by Operator in trust for the Joint Venture or Joint Venturer, as the case may be, and shall not be commingled with other funds or property of Operator.

          3.3 Scope of Operator’s Responsibility. Operator agrees to furnish or cause to be furnished, subject to the conditions and provisions contained herein and in the Joint Venture Agreement, all process and engineering services, drawings, materials, superintendence, labor, equipment, tools and machinery required for the design, construction and installation of the System and agrees to design, construct and install the System in accordance with the Management Committee’s specifications and proposals. The completed System shall be free and clear of all liens and encumbrances for labor and materials used thereon. Upon request by the Joint Venture from time to time, Operator shall submit to the Joint Venture evidence reasonably satisfactory to the Joint Venture of payment of all debts, taxes, liens, claims, charges and obligations arising out of the purchase of equipment, material, supplies or labor for use in the work hereunder.

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ARTICLE 4
Work Inspection

          4.1 Right to Inspect. The Joint Venturers shall be entitled to have their respective inspectors or designees present at any times during the progress of the work to be performed by Operator, subcontractors, vendors or fabricators hereunder, and these parties shall furnish access to any of such work to such inspectors or designees at all times. If any work to be performed by these parties hereunder is found by such inspectors or designees to be unsatisfactory and not in accordance with the governing plans and specifications or drawings previously approved by the Management Committee, then Operator shall, upon written notice from the Management Committee, promptly revise such work in such manner as to conform with said specifications or drawings. It is further agreed that if such revisions are not promptly made, the Management Committee may, upon written notice to Operator require Operator to suspend all work until such revisions have been made.

ARTICLE 5
Personnel

          5.1 Supervision and Compensation of Personnel. Subject to the terms and provisions of the Joint Venture Agreement, Operator shall employ and have supervision over the personnel (including outside consultants and professional, service or other organizations) required by Operator to perform its duties and responsibilities under this Agreement in an efficient and economically prudent manner. Subject to the provisions of Section 3 of the Accounting Procedures attached hereto as Exhibit A, the Joint Venture shall pay all reasonable expenses of such personnel, including compensation, salaries, wages, expenses, social security taxes, worker’s compensation insurance, retirement and insurance benefits and other such expenses.

ARTICLE 6
Method of Payment

          6.1 Direct Payment by Joint Venture and Reimbursement of Operator’s Costs. During the progress of the work to be performed hereunder by Operator, all equipment, materials and machinery which are to be incorporated into and become a component part of the System shall be purchased either directly by the Joint Venture or by the Operator for and on behalf of the Joint Venture. In addition, all labor, tools and supplies necessary to diligently and properly perform the work and complete the construction required hereunder shall be furnished or cause to be furnished by Operator for the benefit of the Joint Venture, and such labor, tools and supplies shall be purchased and paid for either directly by the Joint Venture or by the Operator for and on behalf of

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the Joint Venture. If the Joint Venture has not directly paid for any equipment, materials, machinery, labor, tools and supplies in connection with the work herein provided, then upon the furnishing by Operator of proof satisfactory to the Joint Venture that any bills and expenses for any such labor, tools, material, equipment, machinery and supplies have been paid and fully discharged by Operator, the Joint Venture shall promptly pay and reimburse Operator an amount equal to the total of such payments as may have been made by Operator. Without limiting the foregoing, Operator shall also be reimbursed by the Joint Venture for all other reasonable and proper costs, expenses and expenditures incurred by Operator within the scope of its responsibilities under this Agreement, including the reimbursable costs described in Exhibit A hereto, in each case in accordance with the billing and payment procedures set forth in the Accounting Procedures attached hereto as Exhibit A. Operator shall keep a full and complete account of all costs, expenses and expenditures incurred by it in connection with (i) the design, construction, operation, maintenance and other improvement of the System, including any Joint Venture Expansion, and (ii) all other reimbursable costs.

          6.2 Expenditure Approvals. All construction, operating, maintenance and other expenditures, and the approvals therefor, shall be subject to the terms and provisions of the Joint Venture Agreement.

          6.3 Audit. The Joint Venture shall at all times, upon five (5) day’s prior notice in writing to Operator, have the right during normal business hours to audit, at its own expense, the books and records of Operator as they relate to the Joint Venture and the System and all books and records supporting costs incurred by Operator pursuant to this Agreement.

ARTICLE 7
Indemnity, Administration of Claims and Insurance

          7.1 Indemnity.

               (a) The Joint Venture hereby agrees to indemnify and hold harmless Operator, when acting in its capacity as Operator, and its officers, agents and employees, from and against any loss, claim, damage and liability, joint or several, and any action in respect thereof, insofar as such loss, claim, damage, liability or action arises out of, or is based upon, its duties as Operator, including, without limitation, the design, construction, operation, upkeep, repair, replacement, removal and improvement of the System and any Joint Venture Expansion, and including any loss, claim, damage or liability, joint or several, and any action in respect thereof, arising out of the negligent conduct (but not recklessness, gross negligence or willful misconduct) of Operator, its officers, agents or employees. The Joint Venture agrees to promptly reimburse Operator, its officers, agents and employees, for any legal and other expenses reasonably incurred by Operator

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investigating or defending or preparing to defend against any such loss, claim, damage, liability or action. Indemnification pursuant to this Section 7.1(a) shall be available only to the extent that policies of insurance carried pursuant to Section 7.3 hereof cover such loss, claim, damage, liability or action.

               (b) Operator agrees that it will indemnify and hold the Joint Venture and the Joint Venturers harmless from any and all claims, liens, liabilities or losses arising out of or from Operator’s or any subcontractor’s or materialman’s failure to fully pay all liens, charges, claims, encumbrances and obligations arising by operation of law or otherwise out of Operator’s or any subcontractor’s or materialman’s performance of the work hereunder or the furnishing of any labor, material, equipment, supplies or other items for use in the construction of the System.

          7.2 Administration. Responsibility for the administration of any claims and litigation arising out of the design, construction, operation, maintenance, upkeep, repair, replacement, removal and improvement of the System and any Joint Venture Expansion, or any other matter, shall be as provided for in Section 11.3 of the Joint Venture Agreement. Upon written request from any Joint Venturer, Operator will provide true and complete copies of all documents relating to any claims or litigation and the defense thereof.

          7.3 Insurance. Operator shall carry and maintain in force for the benefit of the Joint Venture and the Joint Venturers insurance of the types and in the amounts required by the Joint Venture Agreement. Upon request by the Joint Venture from time to time, Operator shall furnish certificates to the Joint Venture evidencing that such insurance is in force and that thirty (30) days advance written notice will be given to the Joint Venture prior to any change, non-renewal or cancellation thereof.

ARTICLE 8
Taxes

          8.1 Taxes. Except as provided in Section 9.5(b) and Section 10.12 of the Joint Venture Agreement, the Joint Venture, acting pursuant to the directions of the Management Committee, shall file all tax returns and shall handle all audits related thereto and render and pay with funds provided by the Joint Venture (prior to delinquency) all taxes (except income, excess profits and surcharges thereon, presently and hereinafter enacted) attributable to or arising from the operation, repair and maintenance of the System or the transportation of Gas through the System.

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ARTICLE 9
Term, Termination by Default and Preservation of Rights

          9.1 Term. This Agreement shall continue in force and effect until (i) terminated pursuant to Section 9.2, Section 9.3 or Section 9.4 hereof, (ii) the Joint Venture is dissolved and terminated pursuant to the terms of the Joint Venture Agreement or (iii) the tenth anniversary of this Agreement. whichever shall first occur.

          9.2 Removal of Operator. If Operator defaults in the performance of its duties or obligations under this Agreement, the Joint Venture Agreement or any policies, procedures or rules adopted by the Management Committee in connection with the work to be performed hereunder, the Joint Venture or any Joint Venturer shall have the right to give Operator a notice of default (the “Notice of Default”), which shall set forth the nature of the duty or obligation which Operator has not observed or performed. Upon receipt of any such Notice of Default, Operator shall have the right and be given the opportunity to review and discuss with the Joint Venturers any such Notice of Default. If within the forty (40) day period following receipt of the Notice of Default, the Operator in good faith commences to perform such duty or obligation and cure such default and thereafter prosecutes to completion with diligence and continuity the curing thereof and cures such default within a reasonable time, it shall be deemed that the Notice of Default was not given and the Operator shall not be removed from the office of Operator and shall lose no rights hereunder. If, within such forty (40) day period, the Operator does not commence in good faith the curing of such default or does not thereafter prosecute to completion with diligence and continuity the curing thereof, any Joint Venturer shall have the right to remove the Operator from the office of Operator and terminate this Agreement by giving the Operator and all other Joint Venturers written notice thereof. In the event of its removal, Operator shall have no further responsibility or authority pursuant to this Agreement, except that related to the transfer of responsibility to any successor Operator. Subject to Section 6.1 of this Agreement, Operator shall be reimbursed by the Joint Venture for all expenses it may have reasonably incurred in fulfilling its responsibilities under this Agreement prior to its removal.

          9.3 Withdrawal of Operator. If the Operator is a Joint Venturer, and if the Operator withdraws from the Joint Venture pursuant to any of the provisions set forth in Section 12.2 or Section 12.3 of the Joint Venture Agreement, any Joint Venturer shall then have the right and option to terminate this Agreement upon written notice to the Operator. In the event of its withdrawal, Operator shall have no further responsibility or authority pursuant to this Agreement, except that related to the transfer of responsibility to any successor Operator. Subject to Section 6.1 of this Agreement, Operator shall be reimbursed by the Joint Venture for all expenses it may have reasonably incurred in fulfilling its responsibilities under this Agreement prior to its withdrawal.

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          9.4 Resignation of Operator. At any time after July 31, 2007, Operator may resign as Operator at any time upon sixty (60) days prior written notice to the Joint Venture. In the event of its resignation, Operator shall have no further responsibility or authority pursuant to this Agreement, except that related to the transfer of responsibility to any successor Operator. Subject to Section 6.1 of this Agreement, Operator shall be reimbursed by the Joint Venture for all expenses it may have reasonably incurred in fulfilling its responsibilities under this Agreement prior to its resignation.

          9.5 Preservation of Rights. The termination of this Agreement as a result of the removal, withdrawal or resignation of the Operator (whether in its capacity as a Joint Venturer, Operator only, or both) pursuant to the terms and provisions of the Joint Venture Agreement or this Agreement shall be without prejudice to any other right or remedy the Joint Venture or any Joint Venturer may have as a result of Operator’s removal or withdrawal under the Joint Venture Agreement or this Agreement, or Operator’s resignation under this Agreement.

ARTICLE 10
Laws and Regulations

          10.1 Compliance with Laws. This Agreement and the rights and obligations of the Joint Venture and Operator hereunder shall be subject to all applicable laws, rules, orders and regulations of governmental authorities having jurisdiction, and in the event of conflict, said laws, rules, orders and regulations of governmental authorities having jurisdiction shall control. Operator agrees that it will operate the System as an “intrastate pipeline”, as such term is defined in Section 2(16) of the Natural Gas Policy Act of 1978; and that Operator will not, through any act or omission, cause or contribute to causing the Joint Venture or any Joint Venturer, or any facilities thereof, to become subject in whole or in part of the jurisdiction of the Federal Energy Regulatory Commission or any successor thereto under the Natural Gas Act of 1938, as heretofore or hereafter amended.

          Operator agrees to comply with all applicable laws, rules, regulations, ordinances and requirements of federal, state and local governmental or regulatory bodies having jurisdiction over any aspect of the work performed hereunder. Operator shall indemnify and hold the Joint Venture and the Joint Venturers, and their respective officers, directors, agents and employees, and their respective subsidiary and affiliated companies, and their respective directors, officers, agents and employees, harmless from and against all fines, penalties, expenses or claims resulting from Operator’s failure to abide by any and all applicable laws, rules, regulations, ordinances or requirements of governmental or regulatory bodies having jurisdiction.

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ARTICLE 11
Patents

          11.1 Limitation on License and Royalty Fees. No patented article, method or device which involves or requires the payment of any license fee or royalty in addition to the purchase price shall be used in connection with the work under this Agreement without prior approval of the Management Committee.

ARTICLE 12
Safety

          12.1 Standards. Operator shall comply with the Joint Venture’s safety standards and shall be subject to periodic safety inspections conducted by the Joint Venture. Operator shall also report to the Joint Venture any injury requiring hospitalization or any fatality as soon as practical after the incident. The Joint Venture reserves the right to suspend all work (with or without terminating this Agreement) without penalty if Operator fails to comply with these safety requirements.

ARTICLE 13
Subcontracts

          13.1 Required Approvals. None of the work to be done by the Operator shall be subcontracted without the prior approval of the Management Committee and no approval by the Management Committee to subcontract any portion of such work shall relieve Operator of its primary obligation to the Joint Venture to properly perform such work in accordance with this Agreement.

ARTICLE 14
Force Majeure

          14.1 Force Majeure. If either Operator or the Joint Venture is rendered unable, wholly or in part, by force majeure to carry out its obligations under this Agreement, it is agreed that on such party’s giving notice and reasonable full particulars of such force majeure in writing to the other party as soon as possible after the occurrence of the cause relied on, the obligations of the party giving such notice, so far as to the extent that they are affected by such force majeure, shall be suspended during the continuance of any inability so caused but for no longer period, and such cause shall so far as possible be remedied with all reasonable dispatch.

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     The term “force majeure” as used herein shall mean acts of God, strikes, lockouts or other industrial disturbances, acts of terrorism and the public enemy, wars, blockages, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires not resulting from Operator’s negligence, storms, floods, washouts, laws, rules and regulations, arrests and restraints of government, either federal or state, civil or military, civil disturbances, inability of either party to obtain necessary materials, and any other cause, whether of the kind herein enumerated or otherwise, which is not reasonably within the control of the party claiming suspension. Rain, snow, ice or other adverse weather conditions shall not be considered force majeure. It is understood and agreed that the settlement of strikes or lockouts shall be entirely within the discretion of the party having the difficulty, and that the above requirement that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes or lockouts by acceding to the demands of an opposing party when such course is inadvisable in the discretion of the party having the difficulty.

ARTICLE 15
Miscellaneous

          15.1 Applicable Laws. This Agreement shall be deemed to be a contract made under, and shall be construed in accordance with, and governed by, the laws of the state of Texas; provided, however, that the rights provided in any other agreement entered into in connection herewith with reference to properties covered thereby that are situated in other states may be governed by the laws of such other states.

          15.2 Further Assurances. The Joint Venture and the Operator each hereby agree to execute and deliver such further documents and to do such other acts and things as either other party hereto may reasonably request in order to more fully effect the purposes of this Agreement.

          15.3 Waiver. The parties hereto may (a) mutually agree in writing to extend the time for the performance of any of the obligations or other acts of the other parties hereto, and (b) waive performance of any of the covenants or agreements, or satisfaction of any of the conditions, contained herein. Any agreement on the part of a party hereto to any such extension or waiver shall be valid only if set forth in a written instrument signed on behalf of such party. Except as provided in this Agreement, no action taken pursuant to this Agreement, including any investigation by or on behalf of any party, shall be deemed to constitute a waiver by the party taking such action of compliance with any covenants or agreements contained in this Agreement. The waiver by any party hereto of a breach of any provision hereof shall not operate or be construed as a waiver of any prior or subsequent breach of the same or any other provisions hereof.

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          15.4 Assignment. Operator shall not assign this Agreement or its rights and obligations hereunder without the prior written approval of the Management Committee.

          15.5 Notices. All notices and other communications given or made pursuant to this Agreement shall be in writing and shall be deemed to have been given or made (i) the third business day after the date of mailing, if delivered by registered or certified mail (postage prepaid, return receipt requested), (ii) upon delivery or refusal of delivery, if sent by hand delivery, (iii) upon delivery or refusal of delivery, if sent by prepaid courier (with record of receipt or refusal), or (iv) upon confirmed transmission, if sent by telecopier (with a copy simultaneously sent by certified mail, postage prepaid, return receipt requested), to the parties at the following addresses:

If to Parallel Petroleum Corporation:

Parallel Petroleum Corporation
1004 N. Big Spring, Suite 400
Midland, Texas 79701
Attention: John S. Rutherford
Telecopy: 432-684-3905

If to Capstone Oil & Gas Company, L.P.:

Capstone Oil & Gas Company, L.P.
P.O. Box 10187
Midland, Texas 79702
Attention: Dale Douglas
Telecopy: 432-682-4498

If to Feagan Gathering Company:

Feagan Gathering Company
130 Spring Park Drive, Suite 105
Midland, Texas 79705
Attention: Joe Feagan
Telecopy: (432) 683-5442

          15.6 Amendment. This Agreement may be amended, supplemented or restated only by a written instrument signed by the Joint Venture and the Operator.

          15.7 Conflict. If there is a conflict between any of the terms, conditions, representations, warranties or covenants contained in this Agreement and the terms, conditions, representations, warranties or covenants in the Joint Venture Agreement, the provisions of the Joint Venture Agreement shall govern and control; provided, however,

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the fact that any term, condition, representation, warranty or covenant contained herein is not contained in the Joint Venture Agreement shall not be or be deemed to be, a conflict.

          15.8 Headings. The headings of Articles and Sections contained in this Agreement are provided for reference and convenience only and shall not affect the meaning or interpretation of this Agreement.

          15.9 Counterparts. This Agreement may be executed in any number of counterparts (including by facsimile transmission), each of which shall be an original, but all of which together shall constitute but one and the same instrument. Neither the Joint Venture nor the Operator shall be bound hereby until a counterpart of this Agreement has been executed by both of them.

          15.10 Limitation of Liability. The claims of Operator under this Agreement, if any, shall be limited to the assets of the Joint Venture, and Operator hereby waives any and all rights it may have to proceed against the Joint Venture or the Joint Venturers individually.

          15.11 Entire Agreement; No Third Party Beneficiaries. This Agreement, the Joint Venture Agreement and the documents and instruments to be delivered by the parties in connection with this Agreement and the Joint Venture Agreement (a) constitute the entire agreements and supersede all other prior agreements and understandings, both written and oral, among the parties with respect to the subject matter hereof and the Joint Venture Agreement; and (b) except as otherwise specifically provided herein, are solely for the benefit of the parties hereto and their respective permitted successors, legal representatives and assigns and does not confer on any other person any rights or remedies hereunder.

          15.12 Fair Construction. This Agreement shall be deemed to be the joint work product of the Joint Venture and Operator without regard to the identity of the draftsperson, and any rule or construction that a document shall be interpreted or construed against the drafting party shall not be applicable.

          15.13 Severability. If any term, provision, covenant or restriction of this Agreement is held by a court of competent jurisdiction to be invalid, void or unenforceable, the remainder of the terms, provisions, covenants and restrictions shall remain in full force and effect and shall in no way be affected, impaired or invalidated. It is hereby stipulated and declared to be the intention of the parties that they would have executed the remaining terms, provisions, covenants and restrictions without including any of such which may be hereafter declared invalid, void or unenforceable.

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     IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first written above, to be effective from and after April 1, 2006.

THE JOINT VENTURE
	HAGERMAN GAS GATHERING SYSTEM By Each of Its Joint Venturers Named Below PARALLEL PETROLEUM CORPORATION
	By:	/s/ John S. Rutherford
		John S. Rutherford, Vice President of
		Land and Administration
	CAPSTONE OIL & GAS COMPANY, L.P. By:  Capstone Investments, Inc., its           general partner
	By:	/s/ Dale Douglas
		Dale Douglas, President
	FEAGAN GATHERING COMPANY
	By:	/s/ Mike Feagan
		Mike Feagan, President
THE OPERATOR
	FEAGAN GATHERING COMPANY
	By:	/s/ Joe Feagan
		Joe Feagan, Vice President

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Exhibit A
to
Construction and Operating Agreement

Accounting Procedures

     Section 1. Billing and Payment Procedures. On or before the fifteenth (15^th) day of each month, the Operator shall deliver to the Joint Venture a detailed invoice or request for reimbursement for all costs incurred by or on behalf of the Joint Venture during the previous month and the Joint Venture shall pay such invoice or request for reimbursement within ten (10) days of its receipt thereof. If (i) the Joint Venture is unable to timely pay the full amount of any such invoice or request for reimbursement due to a lack of sufficient funds maintained by the Joint Venture, and (ii) the Operator, for and on behalf of the Joint Venture, pays all or any part of such invoice or request for reimbursement that remains unpaid by the Joint Venture (the “Deficiency Amount”), then the Joint Venture shall be liable to the Operator for the Deficiency Amount, plus interest thereon at the rate of ten percent (10.00%) per annum, commencing on the date such amount is paid by Operator and continuing until the Joint Venture has paid the Deficiency Amount to Operator.

     Section 2. Adjustments. Payment of invoices or requests for reimbursement hereunder shall not prejudice the right of the Joint Venture or any Joint Venturer to protest the correctness thereof; provided, however, all bills and statements rendered during any calendar year shall be presumed to be true and correct after twenty-four (24) months following the end of any such calendar year, unless prior to the end of such period the Joint Venture or any Joint Venturer takes exception thereto and makes a written claim for adjustment by written notice to the Operator and the Joint Venture.

     Section 3. Reimbursable Costs. Operator shall be entitled to be reimbursed for the following costs and expenses:

          (a) Operator’s Direct General and Administrative Costs. Salaries and wages of employees of Operator during the construction, operation, maintenance and improvement of the System, including customary benefits paid to such employees, payroll taxes and insurance, which are directly allocable to time spent on Joint Venture affairs. Allocable time shall be limited to field activities carried out directly on or at the physical System.

          (b) Monthly Management Fee in Lieu of Operator’s Indirect General and Administrative Costs. In lieu of all of Operator’s indirect general and administrative

costs, which are those general and administrative costs that are not directly allocable to time spent on Joint Venture affairs, including, but not limited to, executive, clerical, secretarial, personnel, office service, purchasing, gas accounting, gas procurement and sales, engineering and operations personnel, the Joint Venture shall pay to the Operator a management fee in an amount equal to Nine Thousand Five Hundred and No/100 Dollars ($9,500.00) per month. On May 1, 2007, or as soon thereafter as practicable, the Management Committee and the Operator shall meet for the purpose of reviewing and reconsidering the amount of the monthly management fee payable to the Operator under this Section 3(b). The Management Committee and the Operator shall, acting in good faith and in cooperation with each other, use their best efforts to agree upon (i) whether the monthly management fee should be maintained at the rate of $9,500.00 per month or (ii) whether the monthly management fee should be adjusted upward or downward in order to more accurately reflect the then existing circumstances surrounding the Operator’s services to the Joint Venture.

          (c) Third Party Expenses of Employees. Direct, out of pocket third party expenses incurred by employees whose time is allocable to the Joint Venture under Section 3(a) above, detailed in properly approved expense reports as to meals, lodging, transportation and other related miscellaneous expenses.

          (d) Materials and Supplies. Net cost to Operator, including transportation costs, of new materials and supplies. Used materials or materials employed as substitutes shall be charged at an amount commensurate with their depreciated value (in the case of used items) or the value of the item replaced.

          (e) Fabrication and Inspection Costs. Costs incurred in fabricating materials placed in service on the System and inspection services performed by independent contractors.

          (f) Construction Contractors. Costs incurred for construction contractors. Operator shall employ competitive bidding, unless otherwise directed by the Management Committee. Operator shall obtain the prior approval of the Management Committee before committing to pay amounts to a contractor over and above contract prices, provided that extra work not contemplated in the construction contract shall be paid for as set forth in such contract or a written amendment thereto. Bids shall be obtained whenever practical on all construction projects.

          (g) Routine Expenses. All other expenses incurred by Operator for and on behalf of the Joint Venture pursuant to the duties and responsibilities of Operator described herein, including permits, licenses, right-of-way damages, inspection, maintenance, support contractors, routine legal, equipment rentals and field costs.

Exhibit “B”

to

Joint Venture Agreement

All of the following leasehold acreage located in Chaves County, New Mexico in the lands described below owned by Parallel or Capstone as of the date of this Agreement, and all leasehold acreage located in Chaves County, New Mexico in the lands described below hereafter acquired by Parallel or Capstone, whether by renewal, extension or new lease taken, but only insofar as such renewal, extension or new lease is made or taken on or before March 1, 2009 (in each case, whether jointly or individually owned of record or beneficially by Parallel or Capstone).

Township 12 South, Range 28 East, NMPM: All Sections
Township 12 South, Range 29 East, NMPM: All Sections
Township 13 South, Range 27 East, NMPM: Sections 19 through and including Section 36
Township 13 South, Range 28 East, NMPM: All Sections
Township 13 South, Range 29 East, NMPM: Sections 1 through and including Section 18
Township 14 South, Range 28 East, NMPM: Sections 1 through and including Section 18
Township 14 South, Range 27 East, NMPM: Sections 1 through and including Section 3,
Sections 10 through and including Section 15, Sections 22 through and including Section 27, and
Sections 34 through and including Section 36
Township 14 South, Range 25 East, NMPM: All Sections
Township 14 South, Range 26 East, NMPM: All Sections
Township 14 South, Range 27 East, NMPM: Sections 4 through and including Section 9, Sections
16 through and including Section 21 and Sections 28 through and including Section 33
Township 15 South, Range 24 East, NMPM: Sections 1 through and including Section 3,
Sections 10 through and including Section 15, Sections 22 through and including Section 27, and
Sections 34 through and including Section 36
Township 15 South, Range 25 East, NMPM: Sections 1 through and including Section 31, and
Section 36
Township 15 South, Range 26 East, NMPM: All Sections
Township 15 South, Range 27 East, NMPM: Sections 6 and 7

Gas is committed for all depths.

Exhibit “C”

to

Joint Venture Agreement

GAS GATHERING AGREEMENT

Among

PARALLEL PETROLEUM CORPORATION

and

CAPSTONE OIL AND GAS COMPANY, L.P.

as Producer

and

HAGERMAN GAS GATHERING SYSTEM

as Gatherer

TABLE OF CONTENTS

ARTICLE		PAGE
I	Definitions		2
II	Scope of Agreement		4
III	Quantity		5
IV	Agreement Implementation		7
V	Points of Delivery and Redelivery		9
VI	Pressure		10
VII	Gathering, Compression and Transportation Fees		12
VIII	Quality — Treating and Dehydration Fee		13
IX	Measurement		15
X	Term		19
XI	Taxes		19
XII	Pipeline Operation		20
XIII	Billing and Payments		20
XIV	Right-of-Way		22
XV	Warranty of Title		22
XVI	Regulation		23
XVII	Force Majeure		24
XVIII	Notices and Payments		25
XIX	Relationship of the Parties		26
XX	Insurance During Transportation		27
XXI	Governmental Authority		27
XXII	Priority and Termination of Joint Venture		28
XXIII	General		28
	Exhibit “A”

GAS GATHERING AGREEMENT

     This Gas Gathering Agreement (hereinafter referred to as the “Agreement”), dated as of January 16, 2007, to be effective from and after April 1, 2006, is made by and among Parallel Petroleum Corporation, a Delaware corporation, and Capstone Oil and Gas Company, L.P. (collectively referred to as “Producer”), and Hagerman Gas Gathering System, a joint venture organized under the laws of Texas (“Gatherer”). Producer and Gatherer are collectively referred to as the “parties” and individually as a “party”.

WITNESSETH:

     WHEREAS, Gatherer is engaged or intends to engage in the business of gathering, compressing, treating, dehydrating, processing for liquefiable hydrocarbon recovery and transporting natural gas in Chaves County, New Mexico; and

     WHEREAS, Producer desires, on behalf of itself and the other owners of the jointly owned wells located on the lands within the Contract Area (as defined in Paragraph 3.1 hereof), to have certain wells connected to Gatherer’s pipeline system for the purpose of, among other things, transporting Producer’s natural gas; and

     WHEREAS, Gatherer has constructed, or will cause to be constructed, the necessary pipelines extending from Producer’s wells to points on Gatherer’s pipeline; and

     WHEREAS, such points may require further construction on Gatherer’s facilities, the cost of which will be borne by Gatherer.

     NOW, THEREFORE, in consideration of the premises and of the mutual agreements herein contained, Gatherer and Producer agree as follows:

ARTICLE I

DEFINITIONS

     1.1 In addition to the terms defined elsewhere in this Agreement, the following terms shall have the respective meanings set forth below:

     “Btu” means British thermal unit, which is the quantity of heat required to raise the temperature of one pound of water one (1) degree Fahrenheit at or near 39.2 degrees Fahrenheit.

     “casinghead gas” means gas produced with oil from a well that is classified as an oil well under applicable laws or by ruling, order, or designation of the Oil Conservation Division of the Energy and Minerals Department of the State of New Mexico (the “OCD”).

     “cubic foot of gas” means the quantity of gas contained in one (1) cubic foot of space at a pressure of fourteen and seventy-three hundredths (14.73) psia and at a temperature of sixty degrees (60º) Fahrenheit.

     “day” means a period of twenty-four (24) consecutive hours commencing at 9:00 a.m. on one calendar day and ending at 9:00 a.m. on the following calendar day.

     “gas” means natural gas produced from gas wells and casinghead gas produced in association with oil and residue gas resulting from processing for liquefiable hydrocarbon recovery both gas well gas and casinghead gas.

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     “gas well gas” means all natural gas that is not casinghead gas.

     “Heating Value” means the gross number of Btus produced by combustion, at a constant pressure, of the amount of dry gas which would occupy a volume of one (1) cubic foot at a temperature of sixty degrees Fahrenheit and a pressure of 14.73 psia, with air of the same temperature and pressure of the gas, when the products of combustion are cooled to the initial temperature of the gas and air and the water formed by combustion is condensed to the liquid state, adjusted from ideal to real conditions, and further adjusted to reflect the water vapor content at delivery conditions.

     “liquefiable hydrocarbons” means ethane, propane, isobutane, normal butane and natural gasoline separated or recovered at Gatherer’s plant facilities.

     “Mcf” means one thousand (1,000) cubic feet of gas.

     “month” means a period beginning at 9:00 a.m. on the first day of a calendar month and ending at 9:00 a.m. on the first day of the succeeding calendar month.

     “psia” means pounds per square inch absolute.

     “psig” means pounds per square inch gauge.

     “well” means any well classified as a gas well or as an oil well by the OCD or any other governmental authority having jurisdiction.

     “year” means the period beginning at 9:00 a.m. on the first day of a calendar year and ending at 9:00 a.m. on the first day of the succeeding calendar year; provided that the first year of this Agreement shall commence on the effective date hereof and end on the next succeeding December 31st and the last year of this Agreement shall end at the “termination” hereof.

3

ARTICLE II

SCOPE OF AGREEMENT

     2.1 Pursuant to the terms hereof, Gatherer agrees to (i) operate and maintain its natural gas pipeline system and any additions thereto (collectively, the “System”) which shall extend from the Delivery Point(s) at or near Producer’s wells to the pipeline owned by Transwestern Pipeline Company (“Transwestern”) or other pipeline company designated by Producer at the Point(s) of Redelivery (as defined in Paragraph 5.2), and (ii) receive, gather, dehydrate, treat for CO2, process for recovery of liquefiable hydrocarbons, compress, transport and redeliver any and all gas committed to this Agreement as provided for herein. To expedite connecting Gatherer’s facilities to Transwestern, Producer agrees to pay to Gatherer in advance the estimated cost of connecting Gatherer’s facilities to Transwestern (including rights-of-way, surveying and similar customary charges) prior to the time any wells drilled by the Producer on or before the date of this Agreement and located in the Contract Area (as defined in Paragraph 3.1) are connected to the System and initial deliveries made. Gatherer will thereafter invoice Producer for the actual cost of such construction (which amounts will be offset by Producer’s prior estimated payments). Producer shall not be obligated to pay for any construction costs associated with the connection of any additional wells to the System which are drilled in the Contract Area (as defined in Paragraph 3.1) after the date of this Agreement.

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ARTICLE III

QUANTITY

     3.1 Producer hereby dedicates and commits for the term of this Agreement all its interest in the gas produced and sold from Producer’s wells located on the lands described in Exhibit A attached hereto (the “Contract Area”), subject, however, to the limitations set forth herein and in the preamble of Exhibit A. This Agreement shall not imply or require any leasehold preservation, drilling or development obligations on the part of Producer. Subject to the terms and conditions hereof, Gatherer hereby covenants and agrees that commencing on the date of first deliveries hereunder and continuing until termination of this Agreement, Gatherer will receive all gas tendered by Producer at the Delivery Point(s) under this Agreement. Producer agrees to notify Gatherer in writing when initial deliveries of gas are expected to commence and the expected deliverability rates from each well.

     3.2 If Gatherer fails to connect any well within sixty (60) days from the date Gatherer receives written notification as provided for in Article 3.1, then Producer shall have the right, but not the obligation, to withdraw any such well from the terms of this Agreement and, upon Gatherer’s receipt of written notice from Producer withdrawing any such well, such well shall automatically, and without any further action on the part of Producer or Gatherer, be released from the terms of this Agreement without further obligation or liability of Producer of any kind with respect to such well.

     3.3 Producer expressly reserves for itself, its successors and assigns, the following prior rights with respect to the gas subject hereto:

5

          (a) The right to deliver to lessors under any of the leases subject hereto gas required in kind to meet the requirements of lessee’s obligations under such leases to furnish gas to such lessors.

          (b) The right to use gas reasonably required to develop and operate Producer’s properties in the Contract Area, including, but not limited to, use of gas for drilling, reworking, operating, treating, gas lift and compression fuel.

          (c) Subject to the other provisions of this Agreement, the control, management and operation of the properties subject to this Agreement shall be and remain the exclusive right of Producer. Producer may, in its sole uncontrolled discretion and as it deems advisable, drill new wells, repair or rework old wells, renew or extend in whole or in part any lease or unit, and abandon any well or surrender, terminate or release all or any part of any lease not deemed by Producer capable under normal production methods of producing gas in commercial quantities.

          (d) The right from time to time to alter any gas unit by increasing or decreasing the surface acreage contained therein or to pool or combine any lease or unit or any part thereof with other properties or to include in any unit any interest in lands covered by such unit not theretofore included in such unit; and in the event of any pooling, unitization or change in any unit, this Agreement shall apply only to the interest of Producer in the unit or units and the gas attributable thereto but only insofar as such interest is attributable to the lands and leases committed hereunder.

6

     3.4 Gatherer shall have the right to process, or cause to be processed by others, all gas hereunder for the recovery of liquefiable hydrocarbons prior to the delivery of such gas to Gatherer at the Delivery Point(s) hereunder; provided, however, that the Gatherer shall be obligated to accept the residue gas resulting therefrom in accordance with the terms and provisions hereof.

ARTICLE IV

AGREEMENT IMPLEMENTATION

     4.1 All facilities provided by Gatherer shall be of sufficient design, capacity and capability for receiving, gathering, compressing, dehydrating, treating for CO2, processing for the recovery of liquefiable hydrocarbons, transporting and redelivering the gas subject hereto and shall be provided by Gatherer in accordance with the following:

     (a) volumes of gas transported hereunder shall be redelivered at uniform hourly and daily rates of flow subject to the needs of Producer or its designee at the Point(s) of Redelivery;

     (b) subject to all other provisions of this Agreement, Gatherer shall each day redeliver to Producer or Producer’s designee such daily quantities of gas as are available and tendered by Producer during such day (less fuel, shrinkage and losses) with all deliveries and redeliveries hereunder to be balanced monthly on an MMBtu basis. For each Point of Delivery, Gatherer will allocate to Producer its proportionate share of gas in MMBtus at the Points of Redelivery by multiplying the total MMBtus at the Point of Redelivery (obtained by multiplying the Heating Value by the Mcf at the Redelivery Point) times a ratio, the numerator of which is the MMBtus at that Point of Delivery

7

(obtained by multiplying the Heating Value by the Mcf at the Delivery Point) and the denominator of which is the MMBtus from all Points of Delivery delivering gas into Gatherer’s System; and

     (c) Unless Producer elects to take in kind its share of liquefied hydrocarbons saved and sold (at Producer’s sole cost and expense), Gatherer will allocate to Producer its proportionate share of liquefied hydrocarbons saved and sold at Gatherer’s plant facilities. Allocations will be made on the same basis as in Article 4.1(b).

ARTICLE V

POINTS OF DELIVERY AND REDELIVERY

     5.1 The point of delivery for measurement, allocation and transfer of possession of gas received by Gatherer hereunder shall be at the inlet flange of Gatherer’s meter station located immediately downstream of Producer’s separation facilities (the “Point(s) of Delivery” or “Delivery Point(s)”).

     5.2 The point of redelivery for measurement, allocation and transfer of possession of gas from Gatherer to Producer shall be at the inlet flange of the existing meter located at a point of interconnection of Gatherer’s System and Transwestern Pipeline Company’s meter site located in Section 23, T-14S, R-27E, Chaves County, New Mexico (the “Point(s) of Redelivery” or “Redelivery Point(s)”). One or more additional Points of Redelivery may be designated from time to time by mutual consent of the parties.

     5.3 As between Producer and Gatherer, Producer shall be in control and possession of the gas delivered hereunder until the same shall have been delivered to

8

Gatherer at the Point of Delivery, and Producer shall also be liable and responsible for any damages or injuries resulting from the delivery of the gas until Producer shall have delivered the same to Gatherer at the Point of Delivery, except for damages and injuries which result solely and proximately from Gatherer’s negligence. From and after the Point of Delivery, Gatherer shall be in control and possession of the gas and Gatherer shall be liable and responsible for any leaks, blowouts, damages or injuries caused thereby until the same shall have been redelivered to Producer or Producer’s designee at the Point of Redelivery; provided, however, title to all liquefiable hydrocarbons and gas transported hereunder shall at all times remain in and with Producer.

     5.4 If in Gatherer’s reasonable good faith judgment it becomes commercially unprofitable for Gatherer to maintain and operate a connection at any Point of Delivery, then Gatherer may elect to terminate this Agreement as it applies to any such Point of Delivery by giving Producer one hundred eighty (180) days prior written notice of such election.

ARTICLE VI

PRESSURE

     6.1 The pressure at which Producer shall deliver, or cause to be delivered, gas at each Point of Delivery shall be sufficient to enter Gatherer’s pipeline at each such Point of Delivery from time to time; provided, however, Gatherer’s pressure at the Point(s) of Delivery shall not exceed 400 psig.

     6.2 If any of Producer’s wells become incapable of delivering gas into Gatherer’s pipeline, neither party shall have an obligation to compress, but each party

9

shall have the option to do so. If Gatherer elects not to compress within a reasonable time after the need for compression appears, Producer may, by written notice to Gatherer, request that Gatherer either provide compression or release the affected gas sources as to the then-producing formations from commitment under this Agreement. If Producer requests that Gatherer provide compression, Gatherer shall promptly arrange for providing compression and upon installation of the necessary compression equipment the price to be paid by Gatherer for Producer’s gas shall be increased by a mutually agreeable compression fee that will allow Gatherer to recover its related fuel costs and reasonably compensate Gatherer for such additional costs and services.

     6.3 Producer will furnish and cause to be installed at Producer’s expense, in accordance with customary industry standards, over-pressure protection devices which will control the pressure of gas being delivered to a pressure not in excess of 500 psig. Gatherer shall not be responsible for any gas lost as a result of the failure of the operation of any such pressure devices.

     6.4 If Gatherer’s pressure exceeds 400 psig at the Point of Delivery, Producer may give Gatherer written notice of Gatherer’s breach of this Agreement and Gatherer shall have ninety (90) days after receipt of any such notice to take, at Gatherer’s expense, such actions as may be necessary to cure any such breach of this Agreement. If Gatherer does not cure such breach within the time provided for in this Paragraph 6.4, upon Gatherer’s receipt of written notice from Producer withdrawing such Point of Delivery and the associated gas, such Point of Delivery and associated gas shall automatically, and without any further action on the part of Producer or Gatherer, be released from the terms

10

of this Agreement without further obligation or liability of Producer of any kind with respect to such Point of Delivery and associated gas.

ARTICLE VII

GATHERING, COMPRESSION AND TRANSPORTATION FEES

     7.1 Producer will use its best efforts to deliver a daily volume of 2,000 Mcf to Gatherer at the Point(s) of Delivery for a period of twelve months beginning from the date of first delivery of gas under this Agreement. Producer agrees to pay Gatherer a fee per Mcf measured at the Delivery Point(s) as follows:

     (a) Gathering Fee — Producer will pay a gathering fee of $.25 per Mcf for metering at the Point of Delivery, gathering and delivering gas to a central field point;

     (b) Compression Fee — Producer will pay a compression fee of $.15 per Mcf for compressing gas to a pressure sufficient to enable delivery of gas into Transwestern at the Redelivery Point at approximately 1050 psig, and Producer shall bear its proportionate share of compression fuel; and

     (c) Transportation Fee — Producer will pay a transportation fee in the amount of $.20 per Mcf for the delivery of gas from a central field point through a sixteen inch pipeline to the Points of Redelivery.

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ARTICLE VIII

QUALITY — TREATING AND DEHYDRATION FEE

     8.1 Producer’s gas shall comply at all times with the following specifications: the gas

     (a) shall be commercially free from objectionable odors, objectionable liquid and solid matters, dust, gums, and gum forming constituents, or any other substance which interferes with the intended purpose of merchantability of the gas, or causes interference with the proper and safe operation of the lines, meters, regulators or other appliances through which it may flow;

     (b) shall contain no hydrocarbons in liquid form at the temperature and pressure at which the gas is delivered into the System;

     (c) shall contain not more than 0.2% by volume of oxygen;

     (d) shall contain not more than 2.0% by volume of carbon dioxide;

     (e) shall contain not more than a combined total of 3.0% by volume of carbon dioxide plus nitrogen;

     (f) shall contain not more than one quarter (1/4) grain of hydrogen sulfide;

     (g) shall contain not more than 0.3 grains of mercaptan sulfur per one hundred (100) cubic feet of gas;

     (h) shall contain not more than 0.75 grains of total sulfur per one hundred (100) cubic feet of gas;

12

     (i) shall not contain any toxic or hazardous substance in concentrations which, in the normal use of the gas, may be hazardous to health, injurious to pipeline facilities or limit merchantability or be contrary to applicable government standards;

     (j) shall have a minimum total Heating Value of not less than nine hundred seventy (970) Btu per cubic foot; and

     (k) shall have a temperature of not less than forty (40) degrees Fahrenheit, and not more than one hundred twenty (120) degrees Fahrenheit.

     8.2 If any of the gas delivered by Producer fails in any material respect to meet the quality specifications set forth in Paragraph 8.1, Gatherer may at its option either (i) accept delivery of the gas or (ii) discontinue or curtail taking gas at any Point of Delivery. If Gatherer elects to accept delivery of “off specification” gas and incurs any incremental costs relating to its acceptance and delivery of “off specification” gas into the System, Gatherer shall be entitled to charge Producer an additional fee of $.21 per Mcf.

ARTICLE IX

MEASUREMENT

     9.1 Measurement facilities at the Point(s) of Delivery shall be installed, owned, maintained and operated by Gatherer or its agent. Producer may, at its option and expense, install check measuring and testing equipment for checking the accuracy of the equipment at any Point of Delivery; provided, however, any check measuring and testing equipment installed by Producer shall not interfere with the operation and use of Gatherer’s facilities at the Point of Delivery.

13

     9.2 Gatherer will use its best efforts to cause Transwestern to install, maintain and operate at Transwestern’s expense, at the Points of Redelivery, measuring equipment of a type acceptable to both Gatherer and Producer and of ample size and proper type for the accurate measurement of the gas delivered hereunder, and shall cause said measuring equipment to be read at regular periods which are consistent with accurate measurement. If Transwestern fails or refuses to install, maintain and operate such measuring equipment, then Gatherer shall do so at its sole expense. The location and installation of such measuring equipment shall be such as to prevent, so far as is reasonably possible, pulsations of compressors from interfering with accurate measurement. If at any time or from time to time Gatherer commingles gas from a Point of Delivery with gas from a source other than a Point of Delivery under this Agreement, then Gatherer shall measure such other gas prior to its entering Gatherer’s System.

     9.3 The unit of volume for measurement of gas delivered hereunder shall be one (1) cubic foot of gas. All measurement of gas hereunder shall be determined by calculation in terms of such unit. All fundamental constants, observations, records and procedures utilized in determining or verifying the volume and quality of gas delivered hereunder shall be in accordance with the standards prescribed in aga3 ANSI/API 2530, as now in effect and as hereafter amended or supplemented from time to time.

     9.4 Gatherer, or its designee shall operate the measuring stations located at each Point of Delivery. The reading of electronic flow meters and the calculation of volumes therefrom shall be the responsibility of the Gatherer. The calibration and

14

adjustment of such meters shall be made or arranged for by the parties hereto in compliance with the terms and provisions hereof.

     9.5 The specific gravity of gas committed to this Agreement shall be determined with accuracy to the nearest one thousandth (0.001) by taking samples of the gas at the Point of Delivery at such times as may be designated by any party hereto, but no less often than two (2) times per year. The specific gravity of the gas shall be determined by gas chromatography. The specific gravity determined by any test shall apply from the first day of the month following the date the test was taken until the first day of the month following the next test.

     9.6 Each party shall be given reasonable and sufficient prior notice and shall have the right to be present at the time of installing, reading, cleaning, changing, repairing, inspecting, testing, calibrating or adjusting measuring and testing equipment used by the other party in connection with the delivery of gas hereunder. The records from measuring equipment shall remain the property of the owner of such equipment, but upon request, each party will submit to the other its records and charts, together with calculations therefrom, which shall be returned to the owner within fifteen (15) days after receipt thereof. Test data and other similar records pertaining to the delivery and transportation of gas hereunder shall be retained by the party owning such records for a period of not less than two (2) years.

     9.7 At least once every three (3) months, the Gatherer shall calibrate and adjust meters at the Delivery Points or cause the same to be calibrated and adjusted. The Gatherer shall give Producer sufficient notice in advance of such tests so that Producer

15

may be present to observe the calibration and adjustments, if any, which are made. For purposes of measurement and meter calibrations hereunder, the atmospheric pressure shall be assumed to be fourteen and sixty-five hundredths (14.65) psia, irrespective of variations in natural atmospheric pressure from time to time. Gatherer shall, upon written request of Producer, conduct tests of Gatherer’s measuring equipment; provided, however, in no event shall Gatherer be required to test its measuring equipment more frequently than once each month. All tests of measuring equipment shall be made at Gatherer’s expense, except that Producer shall bear the expense of tests made at its request if the inaccuracy is found to be less than two percent (2.00%).

     9.8 If at any time the metering equipment at the Point of Redelivery is found to be inaccurate by a margin of two percent (2.00%) or more, registration thereof and any payment based upon such registration shall be corrected at the rate of such inaccuracy for any period of inaccuracy which is definitely known or agreed upon, or if not known or agreed upon, then for a period extending back one-half (1/2) of the time elapsed since the last day of calibration. Following any test, any metering equipment found to be inaccurate to any degree shall be adjusted immediately to measure accurately. If, for any reason, any meter at a Point of Delivery is out of service or out of repair so that the quantity of gas delivered through such meter cannot be ascertained or computed from the readings thereof, the quantity of gas delivered during the period the meter is out of service or out of repair shall be estimated and agreed upon by the parties upon the basis of the best available data using one of the following methods which the parties deem to be the most feasible:

16

     (a) by using the registration of any check metering equipment if installed and registering properly;

     (b) by correcting the error if the percentage of error is ascertainable by calibration, test or mathematical calculation; or

     (c) by estimating the quantity or quality of deliveries by deliveries made during preceding periods under similar conditions when the meter was registering accurately.

ARTICLE X

TERM

     10.1 Subject to the other terms and provisions hereof, this Agreement shall be effective from the date hereof and shall thereafter continue and remain in full force and effect for an initial term of ten (10) years and shall continue year-to-year thereafter until either party gives written notice of termination of this Agreement to the other party not less than 60 days prior to any anniversary date of this Agreement.

ARTICLE XI

TAXES

     11.1 Commencing on the effective date hereof, each of the parties hereto shall be solely responsible for and agrees to hold the other party harmless from the payment of any and all taxes or charges of every kind applicable to the gas hereunder or to the transportation hereof pursuant to statutes or orders of governmental authorities having jurisdiction. Neither party shall be responsible or liable for any taxes or other statutory

17

charges levied or assessed against the facilities of the other party used for the purpose of carrying out the provisions of this Agreement.

ARTICLE XII

PIPELINE OPERATION

     12.1 Throughout the term of this Agreement, Gatherer shall have and retain full and continuing responsibility for the care, maintenance and condition of Gatherer’s System and Producer does not assume, nor shall it have any responsibility, obligation or liability for, the care, maintenance and condition of the System. Gatherer shall at all times operate the System, or cause the System to be operated, in a reasonable and prudent manner consistent with customary industry standards and practices pertaining to the gathering and transportation of gas. Gatherer agrees to indemnify and hold harmless Producer from and against any and all loss, costs, claims, damages and expense resulting from Gatherer’s failure to operate the System in accordance with the standards set forth in this Paragraph 12.1.

ARTICLE XIII

BILLINGS AND PAYMENTS

     13.1 Gatherer shall deliver to Producer, no later than fifteen (15) days after the end of each month, a statement and billing of the total quantities of gas received and redelivered hereunder during the preceding month.

     13.2 Producer shall pay to Gatherer on or before the expiration of twenty (20) days after Producer’s receipt of the statement and billing provided for in Paragraph 13.1

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above, all charges, costs and fees billed by Gatherer to Producer in accordance with the provisions of this Agreement.

     13.3 Each party shall have the right to examine at any reasonable time all books, records and measurement data of the other party to the extent necessary to verify the accuracy of any statement or computation made under or pursuant to the provisions of this Agreement.

     13.4 If Producer fails to pay all or any part of any billing for services rendered by Gatherer hereunder or any other charges payable hereunder, interest on the undisputed unpaid amount shall accrue at a rate per annum which is two percent (2.00%) above the prime rate of interest of Wells Fargo Bank Texas, N.A. as announced or published by such bank from time to time (adjusted from time to time to reflect any changes in such rate determined hereunder).

     13.5 If presentation of a bill by Gatherer is delayed to a date after the fifteenth (15th) day of a production month, then the time for payment of such bill shall be extended for a period of time equivalent to the period of delay.

     13.6 If an error is discovered in the amount billed in any statement rendered by Gatherer to Producer, such error shall be adjusted without interest or penalty as soon as reasonably possible, but in any event no later than three (3) months after written notice of such error (the “Notice of Error”) has been given by one party to the other. The computation of fees, and the computation and allocation of MMBtus received at the Delivery Point and redelivered at the Redelivery Point shall be deemed to be correct unless the written Notice of Error is given within two (2) years after the month in which the gas was produced.

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ARTICLE XIV

RIGHT-OF-WAY

     14.1 Insofar as each party is contractually and legally able to do so, each party hereby grants (the “granting party”) to the other party the right to install, operate and maintain equipment utilized hereunder on the property of the granting party and the right of free access to such equipment for purposes relating to this Agreement; but only to the extent such access does not interfere with the granting party’s rights of ownership, operation, use or enjoyment of the property, whether under the terms of this Agreement or otherwise.

ARTICLE XV

WARRANTY OF TITLE

     15.1 Producer warrants title (by, through and under Producer, but not otherwise) to its gas delivered by it hereunder, and warrants that it has the right to deliver the same free from liens and adverse claims of every kind. Each party will indemnify and hold the other party harmless from and against any and all loss, costs, claims, demands, damages and expense of every character with respect to gas delivered by it on account of royalties, taxes, payments or other charges applicable before or upon delivery of the gas.

     15.2 Producer agrees to indemnify and hold Gatherer harmless from and against any and all loss, costs, claims, demands, damages and expense on account of any damage to property or injury to persons arising or resulting from (i) any breach by Producer of its covenants and agreements contained herein or arising or resulting from (ii) Producer’s operations hereunder, unless caused by Gatherer’s negligence or willful misconduct.

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     15.3 Gatherer agrees to indemnify and hold Producer harmless from and against any and all loss, costs, claims, demands, damages and expense on account of any damage to property or injury to persons arising or resulting from (i) any breach by Gatherer of its covenants and agreements contained herein or arising or resulting from (ii) Gatherer’s operations hereunder, unless caused by Producer’s negligence or willful misconduct.

ARTICLE XVI

REGULATION

     16.1 This Agreement shall be interpreted, governed and construed in accordance with the laws of the State of Texas.

     16.2 Both parties represent that all of the gas hereunder will be produced and transported in the State of New Mexico, except as to any transportation of gas authorized to be made pursuant to enabling legislation or regulations of the U.S. Federal Energy Regulatory Commission (“FERC”) which do not subject gas to any increased jurisdiction of FERC and each party recognizes that the other party has entered into this Agreement based upon such representation, and further recognizes that such other party would have been unwilling to enter into this Agreement in the absence of such representation. If either party voluntarily undertakes any course of action that is not required by any governmental agency or law and which results in any portion of the gas delivered hereunder being sold, transported, used, consumed or commingled in such a manner as to increasingly subject such gas to the jurisdiction of FERC or any successor agency, then this Agreement shall be deemed to have terminated by its own terms on the day prior to the date of such occurrence.

21

ARTICLE XVII

FORCE MAJEURE

     17.1 If either party is rendered unable, wholly or in part, by events of “force majeure” to carry out its obligations under this Agreement, other than the obligation to make monetary payments, that party shall give to all other parties prompt written notice of the force majeure event with reasonably full particulars. After such notice has been given, the obligations of the party giving such notice, so far as they are affected by the event of force majeure, shall be suspended during, but no longer than, the continuance of the force majeure event, and the affected party shall use all reasonable diligence to remedy the force majeure event with all reasonable diligence. The term “force majeure” as used herein shall mean all acts of God, strikes, lockouts or other industrial disturbances, acts of terrorism and the public enemy, wars, blockages, insurrections, public riots, lightning, earthquakes, fires not resulting from a party’s negligence, storms, floods, washouts, explosions, inability of either party to obtain necessary materials, supplies, rights-of-ways, permits or labor, and any other cause, whether of the kind specifically enumerated above or otherwise, which is not reasonably within the control of and could not reasonably have been avoided by the party claiming suspension in the exercise of ordinary diligence. It is understood and agreed that the settlement of strikes or lockouts shall be entirely within the discretion of the party involved, and that the above requirement that any force majeure event shall be remedied with all reasonable diligence shall not require the settlement of strikes or lockouts by the party involved.

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ARTICLE XVIII

NOTICES AND PAYMENTS

     18.1 All notices and other communications given or made pursuant to this Agreement shall be in writing and shall be deemed to have been given or made (i) the third business day after the date of mailing, if delivered by registered or certified mail (postage prepaid, return receipt requested), (ii) upon delivery or refusal of delivery, if sent by hand delivery, (iii) upon delivery or refusal of delivery, if sent by prepaid courier (with record of receipt or refusal), or (iv) upon confirmed transmission, if sent by telecopier (with a copy simultaneously sent by certified mail, postage prepaid, return receipt requested), to the parties at the following addresses:

If to the Producer:

Parallel Petroleum Corporation
1004 N. Big Spring, Suite 400
Midland, Texas 79701
Attention: John S. Rutherford
Telecopy: (432) 684-3905

Capstone Oil & Gas Company, L.P.
P.O. Box 10187
Midland, Texas 79702
Attention: Dale Douglas
Telecopy: (432) 683-4498

If to the Gatherer:

Hagerman Gas Gathering System
P.O. Box 50307
Midland, Texas 79710-0307
Attention: Joe Feagan
Telecopy: (432) 683-5442

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or at such address as either party may from time to time designate as the address for such purpose by notice similarly given.

ARTICLE XIX

RELATIONSHIP OF THE PARTIES

     19.1 The parties agree that Producer will tender gas which is owned by Producer for transportation by Gatherer and that gas owned by Producer shall be subject only to the fees and expenses set forth herein. Title to all gas owned by Producer shall remain vested in Producer when delivered to Gatherer for transportation and redelivery hereunder.

     19.2 The relationship of the parties hereto is solely that of Producer and Gatherer setting forth in writing their agreement with respect to the gathering, transportation and delivery of Producer’s gas as set forth herein, and nothing herein shall be construed or deemed to create or constitute any joint venture, partnership or agency between the parties or to authorize either party to bind the other in any manner to any third party whatsoever. The duties, obligations and liabilities of the parties hereto are separate and not joint or collective, and nothing contained herein shall be construed as an obligation of guaranty or indemnification for any indebtedness incurred by the other party in connection with such other party’s performance of its obligations under this Agreement.

ARTICLE XX

INSURANCE DURING TRANSPORTATION

     20.1 As among the parties hereto, it is agreed that Gatherer will obtain insurance against damages or injuries incurred by Producer from and after the Point(s) of Delivery

24

and prior to redelivery of such gas at the Redelivery Point(s). In any event, Producer shall not be responsible for such gas after delivery to Gatherer at the Delivery Point(s) or liable for any damages or injuries incurred during the subsequent gathering, dehydration, treating for CO2, processing for recovery of liquefiable hydrocarbons, compression, transportation and redelivery thereof.

ARTICLE XXI

GOVERNMENTAL AUTHORITY

     21.1 This Agreement and the rights and obligations of the parties hereunder shall be subject to all applicable federal, state and municipal laws, rules, regulations and orders of governmental authorities having jurisdiction. If any provision of this Agreement is abrogated or modified by lawful governmental action, this Agreement shall continue in full force and effect as modified by said governmental action, provided that either party may thereafter, upon ninety (90) days prior written notice to the other party, elect to terminate this Agreement.

ARTICLE XXII

PRIORITY AND TERMINATION OF JOINT VENTURE

     22.1 All gas produced by Parallel Petroleum Corporation and Capstone Oil & Gas Company, L.P., and their respective successors and assigns, and dedicated by them to this Agreement shall have first priority to the availability and capacity of the System, and such gas shall remain subject to and continue to be bound by this Agreement notwithstanding the earlier termination and winding up of the Hagerman Gas Gathering System Joint Venture created by that certain Hagerman Gas Gathering System Joint

25

Venture Agreement, dated as of January 16, 2007, by and among Feagan Gathering Company, Parallel Petroleum Corporation and Capstone Oil & Gas Company, L.P.

ARTICLE XXIII

GENERAL

     23.1 The terms, covenants and conditions hereof shall be binding and inure to the benefit of the parties hereto and their respective successors and assigns.

     23.2 Assignment of this Agreement or any duty hereunder may be made by either party hereto without the prior written consent of the other; provided, however, that no assignment shall have the effect of relieving the assigning party of any liabilities hereunder, past, present or future, unless agreed to in writing by the non-assigning party.

     23.3 The waiver by either party hereto of any breach by the other party of any provision of this Agreement shall not constitute a continuing waiver of such breach or a waiver of any other breach of any other provision of this Agreement.

     23.4 This Agreement may be executed in any number of counterparts (including by facsimile transmission), each of which shall be an original, but all of which together shall constitute but one and the same instrument. Neither party shall be bound hereby until a counterpart of this Agreement has been executed by the other party.

     23.5 Whenever the word “herein” is used in this Agreement, the intended reference is to the entire document, including, without limitation, the paragraph in which such word appears.

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     IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first written above, to be effective from and after April 1, 2006.

HAGERMAN GAS GATHERING SYSTEM
By:	Feagan Gathering Company, Operator
By:	/s/ Joe Feagan
	Joe Feagan, Vice President
PARALLEL PETROLEUM CORPORATION
By:	/s/ John S. Rutherford
	John S. Rutherford, Vice President
	of Land and Administration
CAPSTONE OIL AND GAS COMPANY, L.P.
By:	Capstone Investments, Inc., its general partner
By:	/s/ Dale Douglas
	Dale Douglas, President

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EXHIBIT “A”

to

Gas Gathering Agreement

All of the following leasehold acreage located in Chaves County, New Mexico in the lands described below owned by Parallel or Capstone as of the date of this Agreement, and all leasehold acreage located in Chaves County, New Mexico in the lands described below hereafter acquired by Parallel or Capstone, whether by renewal, extension or new lease taken, but only insofar as such renewal, extension or new lease is made or taken on or before March 1, 2009 (in each case, whether jointly or individually owned of record or beneficially by Parallel or Capstone).

Township 12 South, Range 28 East, NMPM: All Sections
Township 12 South, Range 29 East, NMPM: All Sections
Township 13 South, Range 27 East, NMPM: Sections 19 through and including Section 36
Township 13 South, Range 28 East, NMPM: All Sections
Township 13 South, Range 29 East, NMPM: Sections 1 through and including Section 18
Township 14 South, Range 28 East, NMPM: Sections 1 through and including Section 18
Township 14 South, Range 27 East, NMPM: Sections 1 through and including Section 3,
      Sections 10 through and including Section 15, Sections 22 through and including Section 27, and
      Sections 34 through and including Section 36
Township 14 South,   Range 25 East, NMPM: All Sections
Township 14 South, Range 26 East, NMPM: All Sections
Township 14 South, Range 27 East, NMPM: Sections 4 through and including Section 9,
      Sections 16 through and including Section 21 and Sections 28 through and including Section 33
Township 15 South, Range 24 East, NMPM: Sections 1 through and including Section 3,
     Sections 10 through and including Section 15, Sections 22 through and including Section 27, and
     Sections 34 through and including Section 36
Township 15 South, Range 25 East, NMPM: Sections 1 through and including Section 31, and
     Section 36
Township 15 South, Range 26 East, NMPM: All Sections
Township 15 South, Range 27 East, NMPM: Sections 6 and 7

Gas is committed to all depths.

Exhibit “D”

to

Joint Venture Agreement

Insurance Requirements

(Minimum Requirements)

1.	At all times during the conduct of operations hereunder, Operator shall maintain in force, in accordance with the terms of the Hagerman Gas Gathering System Joint Venture
	Agreement (the “Agreement”), the following minimum limits of insurance at the expense of and for the benefit of the Joint Venture:

(a)	Workers’ Compensation Insurance in accordance with the laws of the state(s) in which operations are covered under the Agreement; and
(b)	Employer’s Liability Insurance with a minimum limit of $1,000,000.

2. In addition to the above, the Operator shall provide and maintain in force the following minimum limits of insurance, at the expense of and for the benefit of the Joint Venture, covering operations on lands subject to the Agreement:

(a)	Commercial General Liability Insurance with a combined single limit of $1,000,000 per occurrence; and
(b)	Automobile Liability Insurance covering owned, non-owned and hired automobiles with a combined single limit of $1,000,000 per accident.

3. Any party may at its own expense acquire such other insurance as it deems proper to protect itself against any claims, losses, damages or destruction arising out of operations under the Agreement.

4. Operator shall require all contractors and subcontractors working on or performing services under the Agreement to comply with applicable Workers’ Compensation and Employer’s Liability laws, both state and federal, and to carry Commercial General Liability and such other insurance as Operator deems necessary.

5. Operator may include Workers’ Compensation and Employer’s Liability Insurance risks under its qualified self-insurance program, provided Operator complies with all applicable laws. In such event, Operator shall charge the Joint Venture with an amount

that shall not exceed the amount of the premium that would be charged at the manual rate effective for insurance coverage as if Operator were a purchaser of such coverage from an insurance company or companies.

6. In connection with all losses, Operator shall (i) furnish copies of accident reports on a prompt basis; (ii) give written notification of the service of all summons and legal processes; (iii) provide information as to the status of any claim or suit of any payment made in connection therewith; and (iv) furnish any other available information required for the purpose of fixing or adjusting premiums or to support any claims.

7. Operator and each Joint Venturer agree to mutually waive subrogation in favor of each other on all insurance carried by each party and/or obtain such waiver from the insurance carrier if so required by the insurance contract. If such waiver is not obtained, the party failing to do so shall indemnify the other party for any claim by an insurance carrier arising out of subrogation.

2

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

Parallel Petroleum Corporation
Midland, Texas

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-146775), Form S-4 (No. 333-148465) and Form S-8 (No. 33-57348, No. 333-34617, No. 333-66938, No. 333-117533 and No. 333-145827) of Parallel Petroleum Corporation of our reports dated February 20, 2008, relating to the consolidated financial statements and the effectiveness of Parallel Petroleum Corporation’s internal control over financial reporting, which appear in this Annual Report on Form 10-K.

/s/ BDO Seidman, LLP

Houston, Texas
 
February 20, 2008

EX-23.2

Exhibit 23.2

Consent of Cawley, Gillespie & Associates, Inc.

     As independent petroleum engineers, we hereby consent to the incorporation by reference in the Registration Statements (No. 333-146775) on Form S-3, (No., 333-148465) on Form S-4 and (No. 33-57348, No. 333-34617, No. 333-66938, No. 333-117533 and No. 333-145827) on Forms S-8 of Parallel Petroleum Corporation of information from our reserves report dated January 22, 2008 and all references to our firm included in or made a part of the Annual Report on Form 10-K of Parallel Petroleum Corporation for the fiscal year ended December 31, 2007.

/s/ Cawley, Gillespie & Associates, Inc.  

Ft. Worth, Texas
February 20, 2008

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, Larry C. Oldham, certify that:

1. I have reviewed this annual report on Form 10-K of Parallel Petroleum Corporation.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report.

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

     (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

     (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

     (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

     (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

     (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

     (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: February 20, 2008	/s/ Larry C. Oldham
	Larry C. Oldham, President and
	Chief Executive Officer (principal executive officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Steven D. Foster, certify that:

1. I have reviewed this annual report on Form 10-K of Parallel Petroleum Corporation.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report.

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

     (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

     (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

     (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

     (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

     (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

     (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: February 20, 2008	/s/ Steven D. Foster
	Steven D. Foster
	Chief Financial Officer (principal financial officer)

EX-32.1

Exhibit 32.1

CERTIFICATION

(Not filed pursuant to the Securities Exchange Act of 1934)

     Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Larry C. Oldham, the President and Chief Executive Officer of Parallel Petroleum Corporation (“Parallel”), hereby certifies that the Annual Report on Form 10-K of Parallel for the year ended December 31, 2007 fully complies with the periodic reporting requirements of the Securities Exchange Act of 1934, as amended, and the information contained in that Form 10-K Report fairly presents, in all material respects, the financial condition and results of operations of Parallel.

Dated: February 20, 2008

/s/ Larry C. Oldham  

Larry C. Oldham, 

President and Chief Executive Officer 

     A signed original of this written statement required by Section 906 has been provided to Parallel Petroleum Corporation and will be retained by Parallel Petroleum Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION

(Not filed pursuant to the Securities Exchange Act of 1934)

     Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Steven D. Foster, the Chief Financial Officer of Parallel Petroleum Corporation (“Parallel”), hereby certifies that the Annual Report on Form 10-K of Parallel for the year ended December 31, 2007 fully complies with the periodic reporting requirements of the Securities Exchange Act of 1934, as amended, and the information contained in that Form 10-K Report fairly presents, in all material respects, the financial condition and results of operations of Parallel.

Dated: February 20, 2008

/s/ Steven D. Foster  

Steven D. Foster, 

Chief Financial Officer 

     A signed original of this written statement required by Section 906 has been provided to Parallel Petroleum Corporation and will be retained by Parallel Petroleum Corporation and furnished to the Securities and Exchange Commission or its staff upon request.