UNITED STATES 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, 2008

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

PARALLEL PETROLEUM CORPORATION

(Exact Name of Registrant as Specified in its Charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)		75-1971716 (I.R.S. Employer Identification No.)
1004 N. Big Spring, Suite 400 Midland, Texas (Address of Principal Executive Offices		79701 (Zip Code)

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

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

Title of Class		Name of Each Exchange on Which Registered
Common Stock, $.01 par value Rights to Purchase Series A Preferred Stock		Nasdaq Global Select Market

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. o

      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 (Do not check if a smaller reporting company)		Smaller reporting company o

     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 2, 2009 was approximately $99,401,654, based on the closing price of the common stock on the same date.

     At February 17, 2009 there were 41,597,161 shares of common stock outstanding.

Documents Incorporated by Reference

     Portions of the registrant’s definitive proxy statement to be filed with respect to the annual meeting of stockholders to be held on or about May 20, 2009 are incorporated by reference into Part III of this Form 10-K.

 

 

FORM 10-K

PARALLEL PETROLEUM CORPORATION

TABLE OF CONTENTS

Item No.		Page
PART I
Item 1. Business			1
Item 1A. Risk Factors			17
Item 1B. Unresolved Staff Comments			35
Item 2. Properties			35
Item 3. Legal Proceedings			40
Item 4. Submission of Matters to a Vote of Security Holders			41
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			42
Item 6. Selected Financial Data			44
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			45
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			74
Item 8. Financial Statements and Supplementary Data			79
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			79
Item 9A. Controls and Procedures			79
Item 9B. Other Information			82
PART III
Item 10. Directors, Executive Officers and Corporate Governance			82
Item 11. Executive Compensation			87
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			91
Item 14. Principal Accountant Fees and Services			92
PART IV
Item 15. Exhibits and Financial Statement Schedules			93
EX-10.24
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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”, “present value”, “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:

	•		difficult and adverse conditions in the global and domestic capital and credit markets;
	•		continued volatility and further deterioration of the capital and credit markets;
	•		uncertainty about the effectiveness of the U.S. government’s plan to purchase large amounts of illiquid, mortgage-backed and other securities from financial institutions;
	•		the impairment of financial institutions;
	•		exposure to financial and capital market risk;
	•		changes in general economic conditions, including the performance of financial markets and interest rates, which may affect our ability to raise capital and generate operating cash flow;

(i)

	•		unanticipated changes in industry trends;
	•		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;
	•		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 17.

     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.

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 and their meanings 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, or the SEC, 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.

Developments in 2008 and 2009

     Adverse Economic Environment. In the last half of 2008, we, along with others in the oil and gas exploration and production industry, began to feel the “fall-out” of the credit crisis, which is ongoing. During this past year, U.S. equity markets dropped sharply, as evidenced by the trading prices of our common stock. During the period from January 1, 2008 to June 30, 2008, the closing price of our stock ranged from a high of $23.22 to a low of $13.15 per share. During the period from July 1, 2008 to December 31, 2008, the closing price of our stock ranged from a high of $20.79 to a low of $1.61 per share. The landscape for companies such as ours changed drastically as a direct result of market turbulence and declines in the financial sector, and steep declines in the price of oil and natural gas. In anticipation of difficult times in the exploration and production segment of the oil and gas industry, we have reduced our capital expenditure budget, and we declined an increase in our borrowing base. In addition, as a result of recent conditions in the capital markets and all of the surrounding uncertainties, we concluded that it would be prudent to draw an additional $62.5 million under our line of credit in order to assure availability of and access to these funds. However, in view of the difficulties experienced by many banking institutions, it is possible that we could also become exposed to certain risks faced by our bank lenders, including legal, political, regulatory, operational and other risks. We depend on our ability to withdraw funds on short notice to meet our obligations. A lender’s insolvency or inability to continue participating in our syndicate of banks in the ordinary course of business could have a material adverse effect our financial condition and results of operations. For more information about the steps we have taken in response to the recent financial downturn, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation - Trends and Outlook”.

     Amended and Restated Credit Agreement. In May 2008, we entered into a Fourth Amended and Restated Credit Agreement, or the “Credit Agreement”, with Citibank, N.A., BNP Paribas, Comerica Bank, Compass Bank, Bank of Scotland, plc, Texas Capital Bank, N.A. and Western National Bank.

     The Credit Agreement provided us with a revolving line of credit which had a “borrowing base” limitation of $230.0 million at the time we entered into the Credit Agreement. The total amount that we could borrow and have outstanding at any one time is limited to the lesser of $600.0 million or the “borrowing base” established by the lenders.

     First Amendment to Credit Agreement. On October 31, 2008, we entered into a First Amendment to our Fourth Amended and Restated Credit Agreement, or the “Revolving Credit Agreement”, amending the Credit Agreement from May 2008 described above. Generally, the Revolving Credit Agreement increased our annual interest rate by one-fourth of one percent (.25%). The borrowing base limitation of $230.0 million remained unchanged with the total amount available to borrow and have outstanding at any one time being limited to the lesser of $600.0 million or the “borrowing base” established by the lenders.

     Second Amendment to Credit Agreement. On February 19, 2009, but effective as of December 31, 2008, we entered into a Second Amendment to our Revolving Credit Agreement. Generally, the Second Amendment increased our annual interest rate for Libor loans by one-fourth of one percent (0.25%). In addition, the Second Amendment modified one of the financial covenants that we must comply with. Before the amendment, our ratio of consolidated funded debt to consolidated EBITDA (calculated at the end of each fiscal quarter using the results of the immediately preceding twelve-month period, each a “test period”) was not allowed to exceed 4.00 to 1.00. After the Second Amendment, this

ratio is not allowed to exceed 4.25 to 1.00 as of December 31, 2008 and for any test period during 2009 and 2010, or 4.00 to 1.00 during the year 2011 and thereafter. See Note 19- “Subsequent Events”.

     The next redetermination of our borrowing base is scheduled to be April 1, 2009. Each borrowing base determination is primarily based upon our then existing quantities of proved oil and gas reserves and commodity prices. However, our lenders are entitled to take into account in their determination of the borrowing base other credit factors that the lenders customarily consider in similar loan facilities, such as cash flow, liabilities, our business and our prospects. Given the current financial crisis in the U.S. economy and the continued uncertainty and volatility in the U.S. capital markets, along with recent declines in oil and gas prices, these other credit factors may become more important to our lenders in their evaluation and determination of any future borrowing base, which could cause any future borrowing base to be lower than expected relative to the value of our oil and gas reserves.

     Our bank lenders at February 2, 2009 included Citibank, N.A., BNP Paribas, Compass Bank, Bank of Scotland plc, Bank of America, N.A., Texas Capital Bank, N.A., Western National Bank and West Texas National Bank. None of the bank lenders held more than 21% of the facility at February 2, 2009. At February 2, 2009, the principal amount outstanding under the revolving credit facility was $225.0 million, excluding $445,000 reserved for our letters of credit; our borrowing base was $230.0 million; and our interest rate was 4.75%, based on Citibank N.A.’s prime rate. For further information regarding our credit facility please refer to Note 11- “Credit Arrangements”.

     Exercise of Warrants. In May 2008, warrants were exercised for a total of 148,757 shares of common stock in a non-underwritten public offering. The shares were issued upon exercise of outstanding warrants that we originally issued in our initial public offering in 1980. Under terms of the warrants, holders of the warrants were entitled to purchase one share of common stock for each warrant exercised. The warrants were exercisable at $6.00 per share on or before May 15, 2008. Net proceeds from the offering, which we used for general corporate purposes, were approximately $796,000. Warrants to purchase 151,273 shares were not exercised and expired by their own terms on May 15, 2008. See Note 13- “Stockholders’ Equity”.

     Acquisitions and Divestitures. In June 2008 we purchased additional interests in our operated Diamond M properties in Scurry County, Texas, effective May 1, 2008. The purchase price of approximately $35.5 million was financed with borrowings under our Credit Agreement. The additional interests acquired represented proved reserves of approximately 2.0 million BOE. The acquired interests consisted of two components, the first component being an 89% working interest in the Base production and reserves, and the second component being a 22.3% working interest in the production and reserves above the Base. The “Base” production and reserves generally means future production and reserves defined by an established base production decline curve as of December 19, 2001. Prior to this acquisition, we did not own an interest in the Base production and reserves but owned a 65.7% working interest in the production and reserves above the Base. This acquisition resulted in an increase in our ownership in the Base production and reserves from zero to an approximate 89% working interest (77% net revenue interest), and an increase in the production and reserves above the Base from a 65.7% working interest to an 88% working interest (76% net revenue interest). See Note 4- “Property Exchange and Acquisitions”.

     Exchange of Senior Notes. In July 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 10¹/4% 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 agreed to use our reasonable best efforts to exchange the senior notes for registered, freely tradable notes having substantially identical terms to the senior notes, and a registration statement on Form S-4 allowing holders of the “old” senior notes to exchange the “old” senior notes for freely tradable senior notes became effective on January 29, 2008. We completed the exchange of the “old” senior notes for “new” registered, freely tradable senior notes on March 4, 2008. See Note 11- “Credit Arrangements”.

     Barnett Shale Farmout Agreement. On February 11, 2009, we entered into a farmout agreement with Chesapeake Energy Corporation, or “Chesapeake”, related to our approximate 35% interest in the Barnett Shale gas project. Under the farmout agreement, for all wells drilled on our Barnett Shale leasehold from November 1, 2008 through December 31, 2016, we have agreed to assign to Chesapeake 100% of our leasehold in the Barnett Shale, subject to the following terms:

	•		all wells drilled from November 1, 2008 through December 31, 2009, and all wells drilled during each succeeding calendar year through 2016 will be treated as a separate project or payout period, creating eight separate projects or payout periods;
	•		at the time Chesapeake commences the drilling of a well during one of the payout periods, we will assign to Chesapeake 100% of our leasehold interest within the subject unit or lease, reserving and retaining a 50% reversionary interest that will vest after Chesapeake recovers 150% of its costs for a particular payout period. Until 150% payout has been reached, Chesapeake will fund 100% of our costs for drilling, completing and operating wells during the payout period;
	•		on each project, Chesapeake is entitled to receive all revenues from our reversionary interest until Chesapeake receives revenues totaling 150% of the drilling, completion and operating costs Chesapeake incurs in funding our reversionary interest;
	•		upon reaching the 150% payout level for a given project, 50% of the interest assigned to Chesapeake will revert back to us;
	•		after 150% project payout, we will pay all costs and receive all revenues attributable to our 50% reversionary interest in each project;
	•		for wells drilled after January 1, 2017, we will pay all costs and receive all revenues attributable to our 50% reversionary interest; and
	•		we will retain all of our interest in wells commenced prior to November 1, 2008, except for 3 wells commenced in late October 2008. We will retain all of our interest in approximately 90 gross (22.4 net) producing wells and 31 gross (9.49 net) wells in progress.

     As non-operator, we do not control the timing of investment in the Barnett Shale gas project. Therefore, we entered into the farmout agreement with Chesapeake. This farmout agreement had a minimal effect on our proved reserves as of December 31, 2008.

     We estimate that our Barnett Shale leasehold acreage operated by Chesapeake and subject to the farmout agreement is approximately 25,600 gross (9,300 net) acres. We anticipate that approximately 61 gross (10.0 net) wells will be drilled and included in the 2009 payout period from November 1, 2008 through December 31, 2009. Payout of each project will depend on drilling and completion costs, timing of completion and pipeline connection to sales, and natural gas prices, among other things.

2009 Capital Budget

     Our 2009 capital investment budget for properties we owned at February 1, 2009 is estimated to be approximately $29.1 million. The budget will be funded from our estimated operating cash flows. If our cash flows are not sufficient to fund all of our estimated capital expenditures, we may fund any shortfall with bank borrowings and proceeds from the sale of our debt or equity securities or sale of oil and natural gas properties, 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.

     We routinely adjust our capital expenditure budget in response to changes in oil and natural gas prices, drilling and acquisition costs, cash flow, drilling results and borrowing base redeterminations under our revolving credit facility.

Proved Reserves as of December 31, 2008

     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 21.2 MMBbls of oil and approximately 71.8 Bcf of natural gas as of December 31, 2008.

     Approximately 64% of our proved reserves are oil and approximately 64% are categorized as proved developed reserves.

About Our Business and Strategy

     We have positioned our property portfolio on 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 productivity in areas that we believe would not have been productive without the use of these advanced technologies and production techniques.

     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 2008, we have replaced approximately 337% of our production. For the year ended December 31, 2008, our depletion per BOE was $15.56, and our related lifting costs, excluding production taxes, were $9.98 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. Chesapeake Energy Corporation, or Chesapeake, as the operator of the majority of our interests in the Barnett Shale natural gas resource play, provides substantial operating expertise in the development of this project. We believe we have significant long-term growth potential through the development of our existing core oil and natural gas properties.

     Approximately 68% of our proved reserves are assigned to our Permian Basin long-lived oil properties and 31% are assigned to our two emerging resource gas projects, the Barnett Shale gas project and the Wolfcamp gas project. As of December 31, 2008, our standardized measure of discounted future net cash flows was $307.9 million. The following table presents proved reserves as of December 31, 2008 by our areas of operation.

		Proved Reserves as of December 31, 2008(1)
		Oil				Natural Gas				Total				% of Total
		(M Bbl)				(M M cf)				(M Boe)				M Boe
Resource projects:
Barnett Shale			—				26,008				4,335				13	%
New Mexico Wolfcamp			1				34,742				5,791				18	%
Total resource projects			1				60,750				10,126				31	%
Permian Basin of West Texas			21,122				8,931				22,610				68	%
Onshore Gulf Coast of South Texas			83				2,152				442				1	%
Total			21,206				71,833				33,178				100	%

     In 2008, we spent $230.6 million on oil and natural gas related capital expenditures, which includes $41.5 million for proved acquisitions, and our 2009 capital budget is $29.1 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 2009 we plan to complete 37 gross wells that were in progress at December 31, 2008, drill 7 gross new wells and to perform approximately 22 gross well workovers, or conversions-to-injection. We plan to allocate our $29.1 million capital budget for 2009 as follows:

	•		$10.2 million for the completion of wells that were in progress at year-end in our north Texas Barnett Shale project;
	•		$5.2 million for the completion of wells that were in progress at year-end, pipeline construction, seismic and leasehold acquisitions in our New Mexico Wolfcamp Carbonate project;
	•		$12.1 million for the completion of wells that were in progress at year-end, the drilling and completion of new wells and workovers of existing wells in our Permian Basin of west Texas properties; and
	•		$1.6 million for the drilling and completion of new wells in our Yegua/Frio and Cotton Valley Reef projects and lease maintenance on our Utah/Colorado project.

Business Segments

     Our operations are conducted in one business segment, oil and natural gas exploration and production.

Our Strategy

     Our strategy has not changed from prior years; however, the activities and acquisitions described below are being impacted by the adverse economic environment developments discussed above and elsewhere in this Annual Report on Form 10-K.

     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, 2008, our lease operating

expense per BOE produced was approximately $9.98, 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.

     Use of 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, such as our Barnett Shale and Wolfcamp gas projects. The successful application of these technologies has increased net production in the Wolfcamp to an average of 14.7 MMcf per day and in the Barnett Shale to an average of 10.3 MMcf per day during the quarter ended December 31, 2008 since the inception of these projects. Our current budget calls for the completion of approximately 31 gross (9.5 net) wells that were in progress at year-end in the Barnett Shale. In the Wolfcamp Carbonate we anticipate completing 3 gross (1.8 net) wells that were in progress at year-end and to refrac 3 gross (2.6 net) wells.

     Use of 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 development 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 which 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 2008

     The following table shows our gross wells drilled, by geographic area, during 2008 and the number of gross wells in process at December 31, 2008.

																		Number of Gross
														Number of				Wells Drilling or				Gross
		Depth												Gross				Waiting on Completion				Productive				Gross
Area		Range (feet)												Wells Drilled				at December 31, 2008				Wells				Dry Wells
North Texas
Barnett Shale			7,000				—				8,000				63				39	(1)			24				—
Permian Basin of West Texas and New Mexico
Carm-Ann			4,000				—				4,500				5				—				5				—
Harris			4,000				—				4,500				10				—				10				—
Fullerton			4,000				—				5,000				5				—				5				—
Wolfcamp Gas			4,300				—				4,500				23				3				20				—
Diamond M Deep			7,000				—				8,000				9				2				7				—
Onshore Gulf Coast of Texas
Frio/Yegua/Wilcox			5,000				—				10,000				2				1				—				1
															117				45				71				1

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,
		2008				2007				2006
		($ in thousands)
Proved property acquisition costs		$	41,481			$	—			$	27,370
Unproved property acquisition costs			41,568				36,750				30,058
Exploration costs			59,290				55,827				71,003
Development costs			88,235				61,766				69,285
		$	230,574			$	154,343			$	197,716

Current Drilling Projects

     Summarized below are our more significant current projects, including our capital budget for these projects in 2009:

     Fort Worth Basin of North Texas

•

Barnett Shale Gas Project, Tarrant County, Texas

     Our 2009 budget for the Barnett Shale project is approximately $10.2 million for the completion of the 31gross (9.5 net) wells that were in progress at year-end including 5 gross (1.56 net) wells that were work-in-progress at the end of 2007.

     Permian Basin of New Mexico

•

Wolfcamp Gas Project, Eddy and Chaves Counties, New Mexico

     Our 2009 New Mexico budget is approximately $5.2 million for the completion of the 3 gross (1.8 net) wells that were in progress at year-end, the re-frac workover of 3 gross (2.6 net) existing wells, the installation of pipelines and related infrastructure, the acquisition and maintenance of leasehold, and the processing and interpretation of 3-D seismic data.

     Permian Basin of West Texas

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

•

Diamond M Canyon Reef Unit & Shallow Leases, Scurry County, Texas

     Our 2009 budget for the Diamond M Canyon Reef and Shallow projects is approximately $7.0 million for the completion of 2 gross (1.8 net) wells that were in progress at year-end, the drilling and completion of 4 gross (3.5 net) new wells, and the workover or deepening of approximately 7 gross (6.2 net) existing wells. Parallel is the operator of these properties with an average working interest of approximately 88%.

•

Carm-Ann San Andres Field, Andrews and Gaines Counties, Texas

     Our 2009 budget for the Carm-Ann San Andres project is approximately $0.9 million for lease and well equipment, telemetry, and unitization costs. Parallel is the operator of these properties with an average working interest of approximately 77%.

•

Harris San Andres Field, Andrews and Gaines Counties, Texas

     Our 2009 budget for the Harris San Andres project is approximately $2.1 million for lease and well equipment, telemetry, unitization costs and the workover of 7 gross (6.3 net) existing wells. Parallel is the operator of these properties with an average working interest of approximately 90%.

•

Fullerton San Andres Field, Andrews County, Texas

     Our 2009 budget for the Fullerton San Andres project is approximately $1.3 million for the drilling of 1 gross (0.4 net) new well and the workover of 5 gross (4.3 net) existing wells. Parallel owns an 85% average working interest in these properties.

     Onshore Gulf Coast of South Texas

•

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

Our 2009 budget for the south Texas projects is approximately $0.8 million for the drilling of 2 gross (0.5 net) new wells.

     Other Projects

•

East Texas Cotton Valley Reef Gas Project, Leon, Freestone and Anderson Counties, Texas

     Our 2009 budget for the east Texas gas project is approximately $0.7 million for the completion of 1 gross (0.2 net) well that was in progress at year-end.

•

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

     Our 2009 budget for the Utah/Colorado project is approximately $0.1 million for the maintenance of leasehold. Parallel owns and operates 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 2008, 2007 and 2006 are shown in the table below.

		Average Price Received for the
		Year Ended December 31,
		2008				2007				2006
Oil (Bbl)		$	95.25			$	65.97			$	59.86
Natural gas (M cf)		$	7.74			$	6.29			$	6.19

     The average price we received during January 2009 for our oil sales was approximately $33.72 per Bbl. At the same date, the average price we were receiving for our natural gas was approximately $5.57 per Mcf.

     Future oil and natural gas prices continue to trend downward. Although this will have a negative impact on our future physical commodity sales values, our derivative contracts will provide a measure of protection by reducing these price fluctuations. We cannot provide any guidance as to where future prices will settle in any given future month.

Employees and Consultants

     At February 2, 2009, we had 46 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.

     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 our gross and net wells drilled during the three-year period ended December 31, 2008.

		Exploratory Wells (1)																Development Wells (2)
Year Ended		Productive								Dry								Productive								Dry
December 31,		Gross				Net				Gross				Net				Gross				Net				Gross				Net
2008			39				10.65				1				0.13				77				37.73				—				—
2007			36				13.93				1				1.00				67				32.29				1				0.37
2006			5				2.87				3				1.42				122				68.35				1				0.08

     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. 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 2, 2009, we were participating in the completion of 4 gross (1.68 net) wells, 20 gross (8.40 net) wells were awaiting completion, 12 gross (3.78 net) wells were shut-in waiting on pipelines and 2 gross (1.13 net) wells were in process of drilling, excluding 21 wells subject to the Barnett Shale Farmout Agreement. See Note 19- “Subsequent Events”.

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, 2008.

		Year Ended December 31,
		2008				2007				2006
		(in thousands, except per unit data)
Production, Prices and Lifting Costs:
Oil (Bbls)			1,027				1,051				1,137
Natural gas (M cf)			10,944				7,422				6,539
BOE			2,851				2,288				2,227
Oil price (per Bbl) (1)		$	95.25			$	65.97			$	59.86
Natural gas price (per M cf) (1)		$	7.74			$	6.29			$	6.19
BOE price (1)		$	64.02			$	50.72			$	48.73
Average Lifting Cost (including production taxes) per BOE		$	13.18			$	11.60			$	10.06

     In 2008, approximately 36% of the volume of our production was oil and 64% 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, 2008.

		2008				2007				2006
		($ in thousands)
Oil revenue		$	97,799			$	69,315			$	68,076
Effect of oil hedges			—				—				(11,512	)
Natural gas revenue			84,716				46,716				40,461
		$	182,515			$	116,031			$	97,025

     Our oil sales in 2008 represented approximately 54% of our combined oil and natural gas revenues (not considering the effect of hedging) for the year ended December 31, 2008, as compared to 60% in 2007, and 63% in 2006.

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.

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

		2008				2007				2006
Chesapeake Operating, Inc.			22	%			12	%			(1)
Conoco, Inc.			18	%			21	%			20	%
Dale Operating Company			(1)				(1)				10	%
Occidental Energy Marketing			10	%			(1)				(1)
Texland Petroleum, Inc.			29	%			30	%			30	%
Tri-C Resources, Inc.			(1)				(1)				12	%

     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 because other purchasers are available in our areas of operations. However, we also believe the current economic downturn has curtailed overall demand for oil and natural gas produced by us and our competitors, a trend we expect will continue for the foreseeable future.

     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 under any existing arrangements or contracts.

     We manage the credit risk associated with our largest customers by using a credit risk monitoring tool to actively monitor credit ratings, including S&P and Moody’s, financial statement filings, financial position, bankruptcy filings and current news.

     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 28,474 square feet of office space at 1004 North Big Spring, Midland, Texas 79701 under two separate leases. Our total current rental rate is $22,401 per month. The first lease covering 22,200 square feet expires on February 28, 2010 and the second lease covering 6,274 square feet expires on May 31, 2011.

     We have three field offices and storage facilities that we own. These three offices are located in Andrews and Snyder, Texas and Hagerman, New Mexico.

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 competitive factors in the acquisition of oil and gas properties include the staff and data necessary to identify, evaluate and acquire such properties and the financial resources necessary to acquire and develop the 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 and securing of qualified labor to conduct our field operations. During periods of 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 labor shortages, we have in the past experienced 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:

	•		leasehold prospects under which oil and natural gas reserves may be discovered or developed;
	•		drilling rigs and related equipment to explore for such reserves;
	•		data necessary to identify, evaluate and acquire properties and the financial resources necessary to carry out the purchase and development of the properties; 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 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 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.
			Wastes containing naturally occurring radioactive materials (“NORM”) may also be generated in connection with our operations. Certain processes used to produce oil and gas may enhance the radioactivity of NORM, which may be present in oilfield wastes. NORM is not subject to regulation under the Atomic Energy Act of 1954, or the Low Level Radioactive Waste Policy Act. NORM is subject primarily to individual state radiation control regulations. In addition, NORM handling and management activities are governed by regulations promulgated by the Occupational Safety and Health Administration (“OSHA”). These state and OSHA regulations impose certain requirements concerning work protection; the treatment, storage and disposal of NORM waste; the management of waste piles, containers and tanks containing NORM; and restrictions on the uses of land with NORM contamination.

	•		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 effect on our operations and demand for our products.

ITEM 1A. RISK FACTORS

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

Risks Related to Our Business

General economic conditions could adversely impact our results of operations.

     A further slowdown in the U.S. economy or other economic conditions affecting capital markets, such as declining oil and gas prices, failing or weakened financial institutions, inability to access cash in our bank accounts, inflation, deteriorating business conditions, interest rates and tax rates, may adversely affect our business and financial condition by reducing overall public confidence in our financial strength, by causing us to further reduce our capital expenditure program and curtail planned drilling activities or by causing the oil field service sector of the domestic oil and gas industry to reduce equipment, labor and services that would otherwise be available to us. Further, some of our properties are operated by third parties whom we depend upon for timely performance of drilling and other contractual obligations and, in some cases, for distribution to us of our proportionate share of revenues from sales of oil and gas we produce. If current economic conditions adversely impact our third party operators, we are exposed to the risk that drilling operations or revenue disbursements to us could be delayed. This “trickle down” effect could significantly harm our business, financial condition and results of operations.

     The consequences of a recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenue, liquidity and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital. These events increase the likelihood that we could become highly vulnerable to further adverse general economic consequences and industry conditions and that our cash flows and financial condition may be materially adversely affected as a result thereof.

     In addition, the instability and uncertainty in the financial markets has made it difficult for us to follow through with drilling operations and other business activities that we had planned on implementing before the current financial crisis. Lower oil and gas prices, the financial markets and U.S. economy have altered our ability and willingness to continue drilling operations at a pace consistent with 2007 and 2008 levels.

     The economic situation could also have an impact on our customers and suppliers, causing them to fail to meet their obligations to us, and on our operating partners, resulting in delays in operations or failure to make required payments. Additionally, the current economic situation could lead to reduced demand for oil and natural gas or further reductions in the prices of oil and natural gas, or both, which could have a negative impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of the current financial crisis cannot be predicted, it may have a material adverse effect on our future liquidity and financial condition.

Adverse capital and credit market conditions may significantly affect our ability to meet liquidity needs, access to capital and cost of capital.

     The capital and credit markets have been experiencing extreme volatility and disruption for more than twelve months. In recent months, the volatility and disruption have reached unprecedented levels. In some cases, the markets have exerted downward pressure on availability of liquidity and credit capacity for certain issuers.

     We need liquidity to pay our operating expenses and interest on our debt. Without sufficient liquidity, we could be forced to curtail our operations, and our business will suffer. The principal sources of our liquidity have been cash flow from our operations, bank borrowings and proceeds from the sale of our debt and equity securities.

     If cash flow from operations and bank borrowings do not satisfy our needs, we may have to seek additional financing. The availability of additional financing will depend on a variety of factors such as market conditions, the general availability of credit, the volume of trading activities, the overall availability of credit to the exploration and production segment of the oil and natural gas industry, our credit ratings and credit capacity, and the possibility that our lenders could develop a negative perception of our long or short-term financial prospects if the level of our business activity decreases significantly due to market downturns. Similarly, our access to funds may be impaired if rating agencies take negative actions against us. Our internal sources of liquidity may prove to be insufficient, and in such case, we may not be able to successfully obtain additional financing on favorable terms, or at all.

     Disruptions, uncertainty or volatility in the capital and credit markets may also limit our access to capital required to operate our business, most significantly our drilling operations. Such market conditions may limit our ability to: replace, in a timely manner, oil and natural gas reserves that we produce; meet maturing liabilities; generate revenue to meet liquidity needs; and access the capital necessary to grow our business. As such, we may be forced to delay raising capital, issue more debt or equity securities than we prefer, or bear an unattractive cost of capital which could decrease our profitability and significantly impair financing alternatives available to us. Our results of operations, financial condition, cash flows and capital position could be materially adversely affected by disruptions in the financial markets.

Difficult conditions in the global capital markets and the economy generally may materially adversely affect our business and results of operations and we do not expect these conditions to improve in the near future.

     Our results of operations are materially affected by conditions in the domestic capital markets and the economy generally. The stress experienced by domestic capital markets that began in the second half of 2008 has continued and substantially increased during the first quarter of 2009. Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market and a declining real estate market in the U.S. have contributed to increased volatility and diminished expectations for the economy and the markets going forward. These factors, combined with volatile oil and gas prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and recession. In addition, the fixed-income markets are experiencing a period of extreme volatility which has negatively impacted market liquidity conditions.

     Initially, the concerns on the part of market participants were focused on the subprime segment of the mortgage-backed securities market. However, these concerns have since expanded to include a broad range of mortgage and asset-backed and other fixed income securities, including those rated investment grade, the U.S. and international credit and interbank money markets generally, and a wide range of financial institutions and markets, asset classes and sectors. As a result, capital markets have experienced decreased liquidity, increased price volatility, credit downgrade events, and increased probabilities of default. These events and the continuing market upheavals may have an adverse effect on us because our liquidity and ability to fund our capital expenditures is dependent in part upon our bank borrowings and access to the public capital markets. Our revenues are likely to decline in such circumstances and our profit margins could erode. In addition, in the event of extreme prolonged market events, such as the global credit crisis, we could incur significant losses. Even in the absence of a market downturn, we are exposed to substantial risk of loss due to market volatility.

     Factors such as business investment, government spending, the volatility and strength of the capital markets, and inflation all affect the business and economic environment and, ultimately, the amount and profitability of our business. In an economic downturn characterized by higher unemployment, lower corporate earnings and lower business investment, our operations could be negatively impacted. Purchasers of our oil and gas production may delay or be unable to make timely payments to us. Adverse changes in the economy could affect earnings negatively and could have a material adverse effect on our business, results of operations and financial condition. The current mortgage crisis has also raised the possibility of future legislative and regulatory actions in addition to the recent enactment of the Emergency Economic Stabilization Act of 2008 (the “EESA”) that could further impact our business. We cannot predict whether or when such actions may occur, or what impact, if any, such actions could have on our business, results of operations and financial condition.

There can be no assurance that actions of the U.S. Government, Federal Reserve and other governmental and regulatory bodies for the purpose of stabilizing the financial markets will achieve the intended effect.

     In response to the financial crises affecting the banking system and financial markets and going concern threats to investment banks and other financial institutions, on October 3, 2008, President Bush signed the EESA into law. Pursuant to the EESA, the U.S. Treasury has the authority to, among other things, purchase up to $700 billion of mortgage-backed and other securities from financial institutions for the purpose of stabilizing the financial markets. The Federal Government, Federal Reserve and other governmental and regulatory bodies have taken or are considering taking other actions to address the financial crisis. There can be no assurance as to what impact such actions will have on the financial markets, including the extreme levels of volatility currently being experienced. Such continued volatility could materially and adversely affect our business, financial condition and results of operations, or the trading price of our common stock.

The impairment of financial institutions could adversely affect us.

     We have exposure to counterparties in the financial services industry, including commercial banks that we rely upon for our credit facilities. In the event of default of one or more of these counterparties, we may have exposure in the form of our ability to withdraw funds on short notice to meet our obligations and short-term investments. We also have exposure to these financial institutions in the form of derivative transactions in that the collectibility of amounts owed to us by a defaulting counterparty may be delayed or impaired. However, our derivative instruments provide rights of setoff of amounts we owe under our credit facilities against amounts owed to us by a counterparty under our derivative transactions.

If the counterparties to the derivative instruments we use to hedge our business risks default or fail to perform, we may be exposed to risks we had sought to mitigate, which could materially adversely affect our financial condition and results of operations.

     We use derivative instruments to mitigate our risks in various circumstances. We enter into a variety of derivative instruments, including swaps, puts and collars with counterparties who are also bank lenders under our credit facility. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk”. If our counterparties fail or refuse to honor their obligations under these derivative instruments, our hedges of the related risk will be ineffective. This is a more pronounced risk to us in view of the recent stresses suffered by financial institutions. Such failure could have a material adverse effect on our financial condition and results of operations. We cannot provide assurance that our counterparties will honor their obligations now or in the future. A counterparty’s insolvency, inability or unwillingness to make payments required under terms of derivative instruments with us could have a material adverse effect on our financial condition and results of operations. However, our derivative instruments allow us to setoff amounts owed to us by a counterparty against amounts that are owed by us to a counterparty under our credit facility. At the date of filing this Annual Report on Form 10-K with the Securities and Exchange Commission, our counterparties included Citibank, N.A. and BNP Paribas. As of December 31, 2008, we had a net derivative asset with Citibank, N.A. of $18.7 million and a net derivative asset with BNP Paribas of $5.6 million.

The fluctuation and volatility of oil and natural gas prices may adversely affect our business, the value of our mineral properties, our revenues and profitability.

     Our business, the value of our oil and natural gas properties and our revenues and profitability are substantially dependent on prevailing prices of oil and natural gas. Our ability to borrow and to obtain additional capital on attractive terms is also substantially dependent upon oil and natural gas prices. Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often causes disruption in the market for acquiring oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for acquisitions, development and exploitation projects. Over the last two years oil prices have fluctuated from approximately $34.00 to approximately $145.00 per barrel. Subsequent to June 30, 2008, the prices of oil and natural gas have declined significantly. Between June 30, 2008 and December 31, 2008, oil prices fell 68% from $140.00 per barrel to $44.60 per barrel, and natural gas prices fell 58% from $13.35 per Mcf to $5.62 per Mcf. If commodity prices continue to decline our financial condition and results of operation would be materially and adversely affected. In addition, any further and extended decline in the price of oil and natural gas could have an adverse effect on our business, the value of our properties, our borrowing capacity, revenues, profitability and cash flows from operations.

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 affected.

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 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, 2008, we owned interests in 533 gross (472.36 net) oil and natural gas wells for which we were the operator and 644 gross (306.79 net) oil and natural gas wells where we were not the operator. Included in these wells are 258 gross (131.30 net) wells which are shut in or temporarily abandoned and 161 gross (134.29 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;

•

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.

diversion of management attention, increasing the scope, geographic diversity and complexity of our operations and incurrence of additional debt.

     Our business strategy includes growing our reserve base through acquisitions. Our failure to integrate acquired properties 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, 2008, approximately 83% 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:

•

production is less than the hedged volumes;

•

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

•

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

     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 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.

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, capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount (the ceiling) equal to the sum of: (i) The after tax present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; (ii) the cost of properties not being amortized; and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized. If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the ceiling, the excess shall be charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off shall not be reinstated for any subsequent increase in the cost center ceiling. This non-cash write-off does not affect cash flow from operating activities, but it does reduce stockholders’ equity.

     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.

     As a result of the steep decline in oil and natural gas prices during 2008, we recognized an impairment of $300.5 million for the fiscal year ended December 31, 2008. We cannot assure you that we will not experience further 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 competitive 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.

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 70% of our estimated future revenues from our proved reserves as of December 31, 2008 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 Related 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 preferred shares as of December 31, 2008. 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;
	•		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 3.10% of the outstanding shares of our common stock as of February 17, 2009.

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 Related to Our 10¹/₄% 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 10¹/₄% senior notes.

     As of December 31, 2008, we had total debt of approximately $370.9 million (of which $145.9 million consisted of our 10¹/₄% senior notes due 2014 net of $4.1 million in unamortized issue discount and $225.0 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;

	•		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, 2008, after taking into consideration our outstanding letters of credit, we have approximately $4.6 million of additional borrowing capacity under our revolving credit facility, 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 restricts 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 10 ¹/₄% 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.

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. Given the current conditions in the credit markets and lower commodity prices, it is possible that the borrowing base under our bank credit facility may be reduced at the time of the next redetermination of our borrowing base, which is scheduled to be April 1, 2009. 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.

     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, 2008, 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, 2008, we had approximately $225.0 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.

     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.

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 areas of operations.

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, 2008. We have not included in the table acreage in which our interest is limited to options to acquire leasehold interests, royalty or similar interests.

		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			—				—				90				22.40				5,450				1,401				28,151				8,936
New Mexico			—				—				90				51.74				18,105				13,386				79,777				64,115
Total Resource Projects			—				—				180				74.14				23,555				14,787				107,928				73,051
Permian Basin of West Texas
Fullerton			170				144.54				—				—				3,683				3,155				—				—
Carm-Ann/N. Means Queen			95				81.69				—				—				4,431				3,949				378				294
Harris			84				74.94				—				—				1,637				1,476				3,428				3,217
Diamond M			103				91.10				—				—				5,805				5,096				—				—
Other Permian			60				27.57				13				10.80				22,439				15,429				—				—
Total Permian Basin			512				419.84				13				10.80				37,995				29,105				3,806				3,511
Onshore Gulf Coast of South Texas
Yegua/Frio/Wilcox			3				0.62				27				6.48				4,332				1,895				2,643				1,036
Cook Mountain			—				—				10				1.04				1,482				166				74				14
Total Onshore Gulf Coast of South Texas			3				0.62				37				7.52				5,814				2,061				2,717				1,050
Other Projects
Cotton Valley			—				—				2				0.30				1,121				100				19,726				3,544
Utah/Colorado			11				0.34				—				—				160				156				179,932				175,786
Total Other Projects			11				0.34				2				0.30				1,281				256				199,658				179,330
Grand Total			526				420.80				232				92.76				68,645				46,209				314,109				256,942

     At December 31, 2008, we owned interests in 533 gross (472.36 net) oil and natural gas wells for which we were the operator and 644 gross (306.79 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 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 8 of this Annual Report on Form 10-K.

Title to Properties

     As is 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 consents to assignment, preferential purchase rights, liens for current taxes not yet due and payable, royalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens materially affect our ownership or the use of our properties.

Oil and Natural Gas Reserves

     For the year ended December 31, 2008, our oil and natural gas reserves were estimated by an independent engineering firm, Cawley, Gillespie & Associates, Inc., Fort Worth, Texas.

     At December 31, 2008, our total estimated proved reserves were approximately 21.2 MMBbls of oil and approximately 71.8 Bcf of natural gas, or 33.2 MMBOE.

     The information in the following table provides you with certain information regarding our proved oil and natural gas reserves as estimated by Cawley, Gillespie & Associates, Inc. at December 31, 2008.

		Proved Developed				Proved Developed				Proved				Total
		Producing				Non-Producing				Undeveloped				Proved
Oil (MBbls)			11,235				902				9,069				21,206
Gas (MMcf)			53,111				2,640				16,082				71,833
MBOE			20,087				1,342				11,749				33,178

     Proved oil and natural 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 oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

     Proved undeveloped oil and natural gas 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.

     The table below shows the production from our oil and natural gas properties for the year ended December 31, 2008 and the proved reserves attributable to those properties as of December 31, 2008.

														Reserves
		Production												Total Proved								Proved Developed
						Natural												Natural								Natural
		Oil				Gas								Oil				Gas				Oil				Gas
		(MBbls)				(MMcf)				MBOE				(MBbls)				(MMcf)				(MBbls)				(MMcf)
Resource Projects
Barnett Shale			—				5,049				842				—				26,008				—				20,262
New Mexico Wolfcamp			1				4,596				767				1				34,742				1				28,302
Total Resource Projects			1				9,645				1,609				1				60,750				1				48,564
Permian Basin of West Texas
Fullerton			518				91				533				7,628				1,208				7,286				1,143
Carm-Ann San
Andres/N. Means Queen			122				60				132				3,424				1,600				919				299
Harris			185				38				191				5,093				677				1,617				269
Diamond M			144				182				174				4,731				3,138				1,986				1,017
Other Permian Basin			37				254				80				246				2,308				245				2,308
Total Permian Basin			1,006				625				1,110				21,122				8,931				12,053				5,036
Onshore Gulf Coast of South Texas			20				674				132				83				2,152				83				2,151
Total			1,027				10,944				2,851				21,206				71,833				12,137				55,751

     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, as adjusted for location differentials, utilized in the estimation of our reserve calculations as of December 31, 2008 were $40.00 per Bbl of oil and $5.18 per Mcf of natural gas.

     For additional information concerning our estimated proved oil and natural gas reserves, you should read Item 7. Management’s Discussion and Analysis-Critical Accounting Policies and Practices and Note 17- “Supplemental Oil and Natural Gas Reserve Data (Unaudited)”.

     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.

ITEM 3. LEGAL PROCEEDINGS

     On April 14, 2008, we were added as a defendant to a lawsuit filed in 2007, styled Brady Briscoe vs. Capstar Drilling, L.P. (“Capstar”), Cause No. 21,287, in the 259th District Court of Jones County, Texas. The plaintiff alleged that he was injured as the result of an accident while he was working, as an employee of an unrelated third party, on a drilling rig operated by Capstar. Capstar was conducting drilling operations for us. The plaintiff asserted general allegations of negligence as to Capstar and, specifically, a failure to properly equip its drilling rig, further alleging we were in charge of the drilling rig and the operational details of the plaintiff’s work. The plaintiff sued for an amount of actual damages of up to $15.0 million, together with pre-judgment interest, post-judgment interest and exemplary damages. Capstar recently settled with the plaintiff and Capstar was dismissed from the lawsuit. If judgment is entered against us, we would be entitled to a credit for the amount that the plaintiff has already received from Capstar. On November 13, 2008, the plaintiff filed notice of non-suit, without prejudice, of all claims and causes of action asserted against us.

     On March 24, 2008, a lawsuit was filed in the 24^th District Court of Jackson County, Texas, against us and twenty-two other defendants in Cause No. 07-6-13069, styled “Tony Kubenka, Carolyn Kubenka, Dennis J. Kallus, David J. Kallus, Mary L. Kallus, Patricia Kallus, Nova Deleon, Janie Figuerova, and Larkin Thedford, Plaintiffs v. Tri-C Resources, Inc., Marie S. Adian, Laura E. Adian, Glenn A. Fiew, Lynn Kramer, Debra Boysen, Carol J. Gleason, Alana Sue Curlee, Connie W. Marthiljohni, Claire E. Adian, Zachary D. Adian, Donald R. Starkweather, Inc., D.A. Webernick, Danette Bundick, Johnny A. Webernick, Donna Gail Glover, Sherry Shulze, William H. Webernick, Jr., TAC Resources, Inc., New Century Exploration, Inc., Allegro Investments, Inc., Parallel Petroleum Corporation and Welper Interests, LP”. The nine plaintiffs in this lawsuit have named us and the other working interest owners, including Tri-C Resources, Inc., the operator, as defendants. The plaintiffs in this lawsuit allege that they are royalty owners under oil and gas leases which are part of a pooled gas unit (the “unit”) located in Jackson County, Texas, and that the defendants, including us, are owners of the leasehold estate under the plaintiffs’ leases and others forming the unit. Plaintiffs also assert that one of the leases (other than plaintiffs’ leases) forming part of the unit has been terminated and, as a result, the defendants have not properly computed the royalties due to plaintiffs from unit production and have failed to properly pay royalties due to them. Plaintiffs have sued for an unspecified amount of damages, including exemplary damages, under theories of breach of contract (including breach of express and implied covenants of their leases) and conversion, and seek an accounting, a declaratory judgment to declare the rights of the parties under the leases, and attorneys’ fees, interest and court costs. If a judgment adverse to the defendants were entered, as a working interest owner in the leases comprising the unit, we believe our liability would be proportionate to the ownership of the other working interest owners in the leases. We have filed an answer denying any liability. Although an initial exchange of discovery has occurred, we cannot predict the ultimate outcome of this matter, but believe we have meritorious defenses and intend to vigorously contest this lawsuit. We have not established a reserve with respect to plaintiffs’ claims.

     We received a Notice of Proposed Adjustment from the Internal Revenue Service, or the “Service” in May 2007 advising us of proposed adjustments to federal income tax of approximately $2.0 million for the years 2004 and 2005. Subsequent discussions with the Service placed the issues contested in a development status. In November 2007, the Service issued a letter on the matter giving us 30 days to agree or disagree with a final examination report. The final examination report reflected revisions of the previous proposed adjustments resulting in a reduced $1.1 million of additional income tax and interest

charges. The decrease in proposed tax was the result of information supplied by us to the examiner as well as discussions of the applicable tax statutes and regulations. In December 2007, we filed a protest documenting our complete disagreement with the adjustments proposed on the final examination report and requested a conference with the appeals office of the Service. The examination office of the Service filed a response to our protest in February 2008 with the appeals office. In response, the additional tax was further reduced by the examination office to $720,000. In June and November of 2008, our representatives met with the Service’s Appeals Officer to review specific issues related to the alternative minimum tax items in dispute. During these meetings we submitted supplements to our initial protest in further support of our position. Currently, the IRS appeals office is considering our information as well as data supplied at the request of the appeals officer. We intend to vigorously contest the adjustment proposed by the Service and believe that we will ultimately prevail in our position. We have not recorded a liability for tax, interest, or penalties related to this matter based on our analysis. If a liability for additional income tax should later be determined to be more likely than not, we anticipate the adjustment to increase the federal income tax liability would be offset by an increase to a deferred tax asset and would not result in a charge to earnings. Any interest or penalties resulting from a subsequent determination of increased tax liability would require a charge to earnings. We believe that the effects of this matter would not have a material effect on our results of operations for the fiscal quarter in which we actually incur or establish a reserve account for interest or penalties.

     We are also presently a named defendant in one other lawsuit arising out of our operations in the normal course of business, which we believe is not material.

     We are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject, 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 2008.

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 Select 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 Select Market.

		Closing Price Per Share
		High				Low
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
2008
First Quarter		$	19.88			$	13.15
Second Quarter		$	23.22			$	19.21
Third Quarter		$	20.79			$	8.62
Fourth Quarter		$	8.87			$	1.61

     The closing price of our common stock on February 19, 2009 was $1.99 per share, as reported on the Nasdaq Global Select Market.

     As of February 19, 2009, there were approximately 1,323 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 fund our capital expenditures 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 prohibit 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 29.

Sale of Unregistered Securities

     At our annual meeting of stockholders held on June 22, 2004, our stockholders approved the Parallel Petroleum Corporation 2004 Non-Employee Director Stock Grant Plan. Only Directors of Parallel who are not employees of Parallel or any of its subsidiaries are eligible to participate in this plan. Under this plan, each non-employee Director is entitled to receive shares of common stock that 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 Global Market for the ten consecutive trading days commencing fifteen trading days before the first day of July of each year. On July 1, 2008, and in accordance with the terms of the plan, a total of 4,612 shares of common stock were granted to four non-employee Directors as follows: Jeffrey G. Shrader — 1,153 shares; Edward A. Nash — 1,153 shares; Martin B. Oring — 1,153 shares; and Ray M. Poage — 1,153 shares. The shares of common stock were issued without registration under the Securities Act of 1933, as amended or, the “Securities Act”, in reliance on the exemption provided by Section 4(2) of the Securities Act. Generally, shares issued under this plan are not transferable as long as the non-employee Director holding the shares remains a Director of Parallel. You can find more information about the 2004 Non-Employee Director Stock Grant Plan on page F-36.

     As a further part of the overall compensation of our non-employee Directors, we granted and issued an additional 7,648 shares of common stock to our four non-employee Directors on June 12, 2008. These stock grants were awarded under our 2008 Long-Term Incentive Plan which was approved by our stockholders at last year’s annual meeting held on May 28, 2008. Each non-employee Director was awarded 1,912 shares of common stock, representing $40,000 divided by $20.91, the closing price of our common stock on the date of grant. In addition to the stock grants described above, Edward A. Nash was also awarded a one-time restricted stock grant of 10,000 shares of common stock. This stock grant vests in four equal annual installments beginning on June 12, 2008, the date of grant. The shares of common stock were issued without registration under the Securities Act in reliance on the exemption provided by Section 4(2). You can find more information about the 2008 Long-Term Incentive Plan on page F-37.

Repurchase of Equity Securities

     Neither we nor any “affiliated purchaser” repurchased any of our equity securities during the fiscal year ended December 31, 2008.

ITEM 6. SELECTED FINANCIAL DATA

     In the table below, we provide you with selected historical financial data for each of the years in the five-year period ended December 31, 2008. We have prepared this information using our audited Consolidated Financial Statements for the five-year period ended December 31, 2008. It is important that you read this financial 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,
		2008(1)				2007				2006(2)				2005				2004
		(in thousands, except per share and per unit data)
Consolidated Income Statement Data:
Operating revenues		$	182,515			$	116,031			$	97,025			$	66,150			$	35,837
Operating expenses		$	392,761			$	67,066			$	56,606			$	32,805			$	23,571
Net income (loss)		$	(131,894	)		$	(4,661	)		$	26,155			$	(1,589	)		$	2,271
Cumulative preferred stock dividend		$	—			$	—			$	—			$	(271	)		$	(572	)
Net income (loss)		$	(131,894	)		$	(4,661	)		$	26,155			$	(1,860	)		$	1,699
Income (loss) per common share
Basic		$	(3.18	)		$	(0.12	)		$	0.73			$	(0.06	)		$	0.07
Diluted		$	(3.18	)		$	(0.12	)		$	0.71			$	(0.06	)		$	0.07
Weighted average common stock and common stock equivalents outstanding
Basic			41,471				38,120				35,888				32,253				25,323
Diluted			41,471				38,120				36,756				32,253				25,688
Cash dividends — common stock		$	—			$	—			$	—			$	—			$	—
Consolidated Balance Sheet Data:
Total assets		$	550,576			$	563,093			$	442,818			$	253,008			$	170,671
Total liabilities		$	443,530			$	327,831			$	259,036			$	163,506			$	110,677
Long-term debt, less current maturities		$	370,890			$	205,383			$	165,000			$	100,000			$	79,000
Total stockholders’ equity		$	107,046			$	235,262			$	183,782			$	89,502			$	59,994
Consolidated Statement of Cash Flow Data:
Cash provided by (used in)
Operating activities		$	121,041			$	74,119			$	68,186			$	35,359			$	17,415
Investing activities		$	(258,297	)		$	(164,897	)		$	(194,548	)		$	(83,190	)		$	(68,777	)
Financing activities		$	165,743			$	92,684			$	125,854			$	49,468			$	38,765
Operating Data:
Product Sales
Oil (Bbls)			1,027				1,051				1,137				923				729
Gas (M cf)			10,944				7,422				6,539				3,592				2,690
BOE			2,851				2,288				2,227				1,522				1,177
Average sales price(3)
Oil (per Bbl)		$	95.25			$	65.97			$	59.86			$	51.78			$	39.05
Gas (per M cf)		$	7.74			$	6.29			$	6.19			$	8.54			$	5.85
Proved reserves
Oil (Bbls)			21,206				28,434				28,721				21,192				18,916
Gas (M cf)			71,833				57,234				58,896				25,237				16,825

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

     The following discussion and analysis 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, 2008. 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 and analysis contains forward-looking statements. For a description of limitations inherent in forward-looking statements, see “Cautionary Statement Regarding Forward-Looking Statements” on page (i).

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 attempt to target our investments in properties expected to produce consistently over the longer term, as contrasted to investments in properties having high rates of production in early years followed by rapid production declines. We also 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.

     Rather than emphasizing high risk exploration activities, we focus 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 from time to time, 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 primary areas of operation.