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, 2006

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

For the transition period from                     to                    

Commission File Number: 0 – 13305

PARALLEL PETROLEUM CORPORATION

(Exact Name of Registrant as Specified in its Charter)

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

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

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

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

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

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

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

Yes o      No þ

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

Yes o       No þ

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

Yes þ      No o

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

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

Large Accelerated Filer þ      Accelerated Filer o      Non-Accelerated Filer þ

     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 21, 2007 was approximately $668,471,227 million, based on the closing price of the common stock on the same date.

     At February 21, 2007 there were 37,547,010 shares of common stock outstanding.

 

 

FORM 10-K

PARALLEL PETROLEUM CORPORATION

TABLE OF CONTENTS

Item No.		Page
PART I
Item 1. Business			1
Item 1A. Risk Factors			13
Item 1B. Unresolved Staff Comments			23
Item 2. Properties			23
Item 3. Legal Proceedings			25
Item 4. Submission of Matters to a Vote of Security Holders			26
PART II
Item 5. Market for Registant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			27
Item 6. Selected Financial Data			28
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			44
Item 8. Financial Statements and Supplementary Data			47
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			47
Item 9A. Controls and Procedures			47
Item 9B. Other Information			49
PART III
Item 10. Directors, Executive Officers and Corporate Governance			50
Item 11. Executive Compansation			54
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			79
Item 13. Certain Relationships and Related Transactions, and Director Independence			81
Item 14. Principal Accountant Fees and Services			84
PART IV
Item 15. Exhibits and Financial Statement Schedules			85
Bylaws
Purchase Warrant Agreement
First Amendment to Warrant Agreement
1998 Stock Option Plan
Incentive and Retention Plan
Guaranty
Third Amended and Restated Pledge Agreement
Second Lien Guarantee and Collateral Agreement
Consent of BDO Seidman, LLP
Consent of Cawley Gillespie & Associates, Inc.
Certification of Principal Executive Officer Pursuant to Section 302
Certification of Principal Financial Officer Pursuant to Section 302
Certification of Principal Executive Officer Pursuant to Section 906
Certification of Principal Financial Officer Pursuant to Section 906

 (i)

Cautionary Statement Regarding Forward -Looking Statements

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

	•		our future financial and operating performance and results;
	•		our business strategy;
	•		market prices;
	•		sources of funds necessary to conduct operations and complete acquisitions;
	•		development costs;
	•		number and location of planned wells;
	•		our future commodity price risk management activities; and
	•		our plans and forecasts.

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

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

	•		fluctuations in prices of oil and natural gas;
	•		demand for oil and natural gas;
	•		losses due to potential or 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;
	•		receipt of amounts owed to us by purchasers of our production and counterparties to our derivative contracts;
	•		decisions to either enter into derivative contracts or not;
	•		events similar to September 11, 2001;
	•		actions of third party co-owners of interests in properties in which we also own an interest;
	•		fluctuations in interest rates;
	•		weaknesses in our internal controls; and
	•		the inherent variability in early production tests.

 (ii)

     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, you should be aware that there are various risks associated with an investment. We have described some of these risks in other sections of this Annual Report on Form 10-K and under Item 1A. Risk Factors, beginning on page 13.

 (iii)

PART I

ITEM 1. BUSINESS

About Our Company

     Parallel Petroleum Corporation, or “Parallel” and its subsidiaries are engaged in the acquisition, development and exploitation of long life oil and natural gas reserves and, to a lesser extent, the exploration 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;
	•		Fort Worth Basin of north Texas; and
	•		the onshore gulf coast area of south Texas.

     In 2006, we spent approximately $195.4 million on oil and natural gas related capital expenditures, an increase of approximately 153 % over that expended in 2005 (See Note 3 to the Consolidated Financial Statements). This amount includes approximately $23.4 million of acquisition costs for additional interests we acquired in our Harris San Andres properties in January 2006. We had previously acquired interests in these same properties in November 2005 for approximately $20.8 million. Also included in our 2006 capital expenditures is $6.1 million for additional interests acquired in our Barnett Shale gas project.

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

	•		Bbl or Bbls — barrel or barrels of oil or other liquid hydrocarbons;
	•		Bcf — billion cubic feet of natural gas;
	•		BOE — equivalent barrel of oil or 6 Mcf of natural gas for one barrel of oil;
	•		MBbls — thousand barrels of oil or other liquid hydrocarbons;
	•		MBoe — thousand barrels of oil equivalent;
	•		MMBbls — million barrels of oil or other liquid hydrocarbons;
	•		MMBoe — million barrels of oil equivalent;
	•		MMBtu — million British thermal units;
	•		Mcf — thousand cubic feet of natural gas; and
	•		MMcf — million cubic feet of natural gas.

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

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

Available Information

     You may read and copy any materials we file with, or furnish to, the Securities and Exchange Commission at the SEC’s public reference facilities at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference facilities by calling the SEC at 1-800-SEC-0330. The SEC maintains a website (http://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 http://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 2006; 2007 Capital Budget

     On August 16, 2006, we sold 2,500,000 shares of our common stock in a public offering at a price of $25.25 per share. Gross cash proceeds were approximately $63.1 million, and net proceeds were approximately $60.3 million. The proceeds were used for general corporate purposes, including debt repayment and the acceleration of our drilling and completion operations in core areas of our operations, including our Barnett Shale and New Mexico Wolfcamp gas projects and our oil properties in the Permian Basin of west Texas.

     Our 2007 capital investment budget for properties we owned at February 15, 2007 is estimated to be approximately $155.6 million, which includes $14.0 million for the purchase of leasehold and seismic in our areas of activity. The budget will be funded from our estimated operating cash flows and our bank borrowings. If our cash flows and bank borrowings are not sufficient to fund all of our estimated capital expenditures, we may fund any shortfall with proceeds from the sale of our debt or equity securities, reduce our capital budget or effect a combination of these alternatives. The amount and timing of our expenditures are subject to change based upon market conditions, results of expenditures, new opportunities and other factors.

Proved Reserves as of December 31, 2006

     Cawley Gillespie & Associates, Inc., our independent petroleum engineers, estimated the total proved reserves attributable to all of our oil and natural gas properties to be approximately 28.7 MMBbls of oil and approximately 58.9 Bcf of natural gas as of December 31, 2006.

     Approximately 75% of our proved reserves are oil and approximately 51% are categorized as proved developed reserves.

About Our Strategy and Business

     From 1993 until mid 2002, our activities were concentrated in the onshore gulf coast area of south Texas. In June 2002, we reexamined and revised our business strategy. We shifted the balance of our investments from properties having high rates of production in early years to properties with more consistent production over a longer term. We now emphasize reducing drilling risks by dedicating a smaller portion of our capital to high risk projects, while reserving the majority of our available capital for acquisition, exploitation, enhancement and development drilling opportunities. Obtaining positions in long-lived oil and natural gas reserves is given priority over properties that might provide more cash flow in the early years of production, but which have shorter reserve lives. Our risk reduction efforts also include emphasizing acquisition possibilities over high risk exploration projects.

     Since the latter part of 2002, we have reduced the emphasis on high risk exploration efforts and we now focus primarily on established geologic trends where we can better 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 the principal criteria in the execution of our business plan.

     In summary, our current business plan:

	•		focuses on projects having less geological 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 our operations by diversifying our exploratory and development efforts, both in and outside of our current core areas of operation.

     An integral part of our business strategy includes exploitation and enhancement activities. Exploitation and enhancement activities include:

	•		operational enhancements, such as surface facility reconfiguration, and the installation of new or additional compression equipment;
	•		workovers;
	•		well recompletions;
	•		behind-pipe recompletions;
	•		refracing (restimulating a producing formation within an existing wellbore to enhance production and add reserves);
	•		installation of injection wells and related facilities;
	•		development well drilling (infill drilling);
	•		cost reduction programs; and
	•		secondary recovery operations, including waterfloods.

     When we initiate exploitation and enhancement activities on our existing producing properties, we first establish and maintain an ongoing program of oil and natural gas well reviews with the objective of maximizing the production from existing wells. Oil and natural gas wells usually generate their highest volumes during the earlier stages of production after which production begins to decline. Enhancement and remedial work can be undertaken to restore varying amounts of lost production or reduce the rate of production decline.

     Our approach to producing property acquisitions, and the size and timing of any acquisition, is dependent upon market conditions in the domestic oil and natural gas industry. Generally, during periods of moderate to high prices for oil and natural gas, we believe that oil and natural gas acquisition opportunities are not as favorable to a prospective purchaser as they are when market conditions are depressed.

     Producing properties that we identify and attempt to acquire will include properties that have proved undeveloped and behind-pipe reserves, operational enhancement potential, long-lived reserves, multiple pay-zone exploitation and development drilling opportunities. We believe that selecting and acquiring producing properties having these characteristics will diversify and improve the overall quality of our property portfolio.

     Although purchases of producing properties involve less risk than drilling, there is a risk that estimates of future prices or costs, reserves, production rates or other criteria upon which we have based our investment decision may prove to be inaccurate.

     In addition to acquisitions of producing properties, our business strategy also includes seeking opportunities to negotiate and enter into “work to earn”, joint venture and similar agreements with third parties for development operations on producing properties.

     Our sources for possible acquisitions of leases and prospects include independent landmen, independent oil and natural gas operators, geologists and engineers. We also evaluate properties that become available for purchase. If our review of an undeveloped lease or prospect or a producing property indicates that it may have geological characteristics favorable for 3-D seismic analysis, we may decide to acquire a working interest in the property or an

option to acquire a working interest. In the case of producing properties, we also seek properties that we believe are underperforming relative to their potential. To reduce our financial exposure in any one prospect, we generally enter into co-ownership arrangements with third parties. These arrangements are common in the industry and enable us to participate in more prospects and share the drilling and related costs and dry-hole risks with other participants. From time to time, we sell prospects to third parties or farm-out prospects and retain an interest in revenues from these prospects.

     As we have in the past, we continue to:

     (1) Use Horizontal Drilling and Fracture Stimulations - We believe the use of horizontal drilling and fracture stimulations have enabled us to develop reserves economically such as our Barnett Shale and Wolfcamp gas projects.

     (2) Use Advanced Technologies - We believe the use of 3-D seismic surveys, horizontal drilling, fracture stimulation and other advanced technologies are useful risk management tools that help reduce the normal drilling and operations risks associated with our day-to-day activities. We believe that our use of these technologies 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.

     Generally, 3-D seismic surveys provide more accurate and comprehensive information to evaluate drilling prospects than conventional 2-D seismic technology. We evaluate substantially all of our exploratory prospects using 3-D seismic technology. On certain prospects we use 3-D seismic techniques that identify structure and compartmentalization of the target reservoir. On other exploratory prospects, we also use amplitude versus offset, or AVO analysis. AVO analysis shows the contrast between sands and shales and assists us in determining the presence of natural gas in potential reservoir sands.

     We believe that using 3-D seismic, AVO and other technologies gives us a competitive advantage because of the increased likelihood of successful drilling. When we evaluate exploratory prospects in geographical areas where the use of 3-D and other advanced technologies are not likely to provide any advantages, we use traditional evaluation methods, such as 2-D seismic technology.

     (3) Serve as Geophysical Operator - We prefer to serve as the geophysical operator for projects located in areas where we have experience using 3-D seismic technology. By doing so, we control the design, acquisition, processing and interpretation of 3-D surveys and, in most cases, determine drilling locations and well depths. The integrity of 3-D seismic analysis in our projects is enhanced by emphasizing quality controls throughout the data acquisition, processing and interpretation phases.

     We retain experienced outside consultants and participate with knowledgeable joint working interest owners when we acquire, process and interpret 3-D seismic surveys. When possible, we also attempt to correlate or model the interpretations of 3-D seismic surveys with wells previously drilled on or near the prospect being evaluated.

     (4) Conduct Exploratory Activities - Although we do not emphasize exploratory drilling to the extent we have in the past, when we do undertake exploratory projects, we will continue to focus on prospects:

	•		having known geological and reservoir characteristics;
	•		being 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
	•		having a potentially meaningful impact on our reserves.

Drilling Activities in 2006

     The following table shows our gross and net wells drilled, by geographic area, during 2006.

										Number of Wells
						Number of				Drilling or				Gross
		Depth				Gross				Waiting on Completion				Productive				Gross
Area		Range (feet)				Wells Drilled				at December 31, 2006				Wells				Dry Wells
North Texas
Barnett Shale			7,000 - 8,000				13				2				11				0
Permian Basin of west Texas and New Mexico
Carm-Ann/Means			4,000 - 4,500				15				2				13				0
Harris			4,000 - 4,500				30				3				27				0
Fullerton			4,000 - 5,000				6				0				6				0
Wolfcamp Gas			4,300 - 4,500				59				16				42				1
Diamond M (Deep )			6,500 - 7,000				2				0				2				0
Onshore Gulf Coast of Texas			—
Frio/Yegua/Wilcox			5,000 - 10,000				4				0				2				2
Cotton Valley			16,000 - 18,000				1				1				0				0
Utah			4,000 - 5,000				1				0				0				1
							131				24				103				4

Drilling and Acquisition Costs

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

		Year Ended December 31,
		2006				2005				2004				2003				2002
		($ in thousands)
Proved property acquisition costs		$	27,370			$	23,763			$	39,763			$	2,209			$	48,044
Unproved property acquisition costs			30,058				11,743				7,400				3,831				2,295
Exploration costs			71,003				15,455				6,794				3,240				1,291
Development costs			66,965				26,390				13,954				5,650				9,308
		$	195,396			$	77,351			$	67,911			$	14,930			$	60,938

Current Drilling Projects

     Summarized below are our more significant current projects, including our capital budget for these projects in 2007:

     Resource Natural Gas Projects

     We have two resource natural gas projects in varying stages of development. They are the Barnett Shale gas project in the Fort Worth Basin of north Texas and the Wolfcamp gas project in the Permian Basin of New Mexico. These resource natural gas projects generated approximately 34% of our fourth quarter 2006 daily production (2,055 BOE per day) and represented approximately 9% of our total proved reserve value as of December 31, 2006.

     We have budgeted approximately $125.4 million for these two resource natural gas projects in 2007 for the drilling and completion of approximately 86 new gross wells, leasehold acquisition, pipeline construction and pipeline compression.

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

     • Barnett Shale Gas Project, Tarrant County, Texas – This project generated approximately 17% of our fourth quarter 2006 daily production (1,013 BOE per day) and represented approximately 4% of our total proved reserve value as of December 31, 2006.

     Our leasehold position in the Barnett Shale gas project includes approximately 19,000 gross (5,100 net) acres. We have budgeted approximately $49.0 million for this project in 2007 for the drilling and completion of 34 new gross wells, pipeline construction and leasehold acquisition. As of January 25, 2007, there were 5 drilling rigs running and 2 wells awaiting completion and pipeline connection in the Barnett Shale gas project.

     • Wolfcamp Gas Project, Eddy and Chavez Counties, New Mexico – This project generated approximately 17% of our fourth quarter 2006 daily production (1,042 BOE per day) and represented approximately 5% of our total proved reserve value as of December 31, 2006.

     Our New Mexico Wolfcamp gas project consists of three areas of mutual interest in which the primary target is the Wolfcamp formation at a depth of approximately 4,500 feet. Our leasehold position in the project includes approximately 152,000 gross (63,000 net) acres. We anticipate participating in the drilling of approximately 52 horizontal wells in New Mexico during 2007. If all of these wells are drilled, we will serve as operator of 40 wells, and 12 will be non-operated. We have budgeted approximately $76.4 million for this project in 2007 to fund the drilling and related leasing and infrastructure activity.

     Permian Basin of West Texas

     The Permian Basin of west Texas generated approximately 55% of our fourth quarter 2006 daily production (3,358 BOE per day) and represented approximately 87% of our total proved reserve value as of December 31, 2006. Our significant producing properties in the Permian Basin of west Texas are described below.

     • Fullerton San Andres Field, Andrews County, Texas – This non-operated property generated approximately 25% of our fourth quarter 2006 daily production (1,544 BOE per day) and represented approximately 33% of our total proved reserve value as of December 31, 2006.

     We have budgeted approximately $1.2 million to fund 18 re-fracs in 2007. Our average working interest in the Fullerton properties is approximately 82%.

     • Carm-Ann San Andres Field / N. Means Queen Unit, Andrews & Gaines Counties ,Texas – These properties generated approximately 9% of our fourth quarter 2006 daily production (560 BOE per day) and represented approximately 14% of our total proved reserve value as of December 31, 2006.

     We have budgeted approximately $8.1 million for the Carm-Ann/N. Means Queen properties in 2007 for 16 re-fracs and 12 new infill wells. Our average working interest in these properties is approximately 77%.

     • Harris San Andres Field, Andrews and Gaines Counties, Texas – These properties represented approximately 10% of our fourth quarter 2006 daily production (608 BOE per day) and represented approximately 23% of our total proved reserve value as of December 31, 2006.

     We have budgeted approximately $8.5 million for the Harris San Andres properties in 2007 for 16 re-fracs and 12 new drills.

     • Diamond M Canyon Reef Unit, Scurry County, Texas – This property generated approximately 5% of our fourth quarter 2006 daily production (301 BOE per day) and represented approximately 8% of our total proved reserve value as of December 31, 2006.

     A total of $6.5 million has been budgeted in 2007 to fund the workover of 6 wells, the drilling of 9 new wells, the processing and interpretation of a new 3-D seismic survey and associated equipment upgrades. Our average working interest in these properties is approximately 66% above the contractual base volumes associated with our work-to-earn arrangement with Southwestern Energy Company.

     Onshore Gulf Coast of South Texas

     • Yegua/Frio/Wilcox Gas Project, Jackson, Wharton and Liberty Counties, Texas – This project generated approximately 10% of our fourth quarter 2006 daily production (629 BOE per day) and represented approximately 3% of our total proved reserve value as of December 31, 2006.

     We have budgeted approximately $1.7 million for the Yegua/Frio/Wilcox gas project in 2007 for the drilling and completion of 2 wells.

     Other Projects

     • Utah/Colorado CBM (Coal Bed Methane) Gas/Conventional Oil and Natural Gas Projects, Uinta Basin – This project does not yet contribute to our current daily production or reserve value.

     As of December 31, 2006, our leasehold acreage position in this project was approximately 160,000 gross (152,000 net) acres. It is a multiple zone project consisting of both oil and natural gas targets at a depth of less than 6,000 feet. Seismic and geological data evaluation on this project continues.

     We have budgeted approximately $3.9 million for the Utah/Colorado CBM gas project in 2007 for drilling and completion of 2 wells and the acquisition of additional 3-D seismic surveys and additional leasehold.

Oil and Natural Gas Prices

     The average wellhead prices we received for the oil and natural gas we produced in 2006, 2005 and 2004 are shown in the table below.

		Average Price Received for the
		Year Ended December 31,
		2006				2005				2004
Oil (Bbl)		$	59.86			$	51.78			$	39.05
Natural gas (Mcf)		$	6.19			$	8.54			$	5.85

     The average price we received for our oil sales at February 1, 2007 was approximately $54.49 per Bbl. At the same date, the average price we were receiving for our natural gas was approximately $6.27 per Mcf.

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

Employees and Consultants

     At February 1, 2007, we had 41 full time employees. Mr. Cambridge, Chairman of the Board of Directors, serves in the capacity of a consultant and not as a full-time employee. 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 certain information concerning the number of gross and net wells we drilled during the three-year period ended December 31, 2006.

		Exploratory Wells (1)																Development Wells (2)
Year Ended		Productive								Dry								Productive								Dry
December 31,		Gross				Net				Gross				Net				Gross				Net				Gross				Net
2006			5.0				2.87				3.0				1.42				122.0				68.4				1.00				0.08
2005			21.0				5.32				6.0				0.64				48.0				27.5				—				—
2004			17.0				1.68				4.0				0.95				50.0				31.8				—				—

     All of our drilling is performed on a contract basis by third-party drilling contractors. We do not own any drilling equipment.

     At February 1, 2007, we were participating in the completion of 8 gross (3.53 net) wells, 6 gross (1.60 net) wells were awaiting completion and 9 gross (3.04 net) wells were in process of drilling.

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, 2006.

		Year Ended December 31,
		2006				2005				2004
		(in thousands, except per unit data)
Production, Prices and Lifting Costs:
Oil (Bbls)			1,137				923				729
Natural gas (Mcf)			6,539				3,592				2,690
BOE			2,227				1,522				1,177
Oil price (per Bbl)(1)		$	59.86			$	51.78			$	39.05
Natural gas price (per Mcf)(1)		$	6.19			$	8.54			$	5.85
BOE price(1)		$	48.73			$	51.57			$	37.55
Average Lifting Cost (including production taxes) per BOE		$	9.91			$	9.24			$	8.06

     In 2006, approximately 51% of the volume of our production was oil and 49% 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 Wilcox assets.

     The following table summarizes our revenues by product sold for each year in the three year period ended December 31, 2006.

		2006				2005				2004
		($ in thousands)
Oil revenue		$	68,076			$	47,800			$	28,455
Effect of oil hedges			(11,512	)			(12,139	)			(7,458	)
Natural gas revenue			40,461				30,690				15,735
Effect of natural gas hedges			—				(201	)			(895	)
		$	97,025			$	66,150			$	35,837

     Our oil sales in 2006 represented approximately 63% of our combined oil and natural gas revenues (not considering the effect of hedging) for the year ended December 31, 2006, as compared to 61% in 2005, and 64% in 2004.

Markets and Customers

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

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

		2006				2005				2004
Allegro Investments, Inc.			(1)				14	%			22	%
Conoco, Inc.			20	%			12	%			(1)
Texland Petroleum, Inc.			30	%			40	%			43	%
Tri-C Resources, Inc.			12	%			(1)				(1)
Dale Op erating Comp any			10	%			(1)				(1)

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

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

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

Office Facilities

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

     We have two field offices and storage facilities. These two offices are located in Andrews and Snyder, Texas. The current monthly rental rate is $750 for the Andrews office and $1,200 for the Snyder office. The Andrews office lease expires December 1, 2007. The Snyder office lease expires upon the cessation of production from the Diamond “M” area wells.

Competition

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

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

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

	•		adequate capital resources for projects in our core areas of operations;
	•		the technological capabilities to conduct a thorough evaluation of a particular project; and
	•		a small staff that can respond quickly to exploration and acquisition opportunities.

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

	•		leasehold prospects under which oil and natural gas reserves may be discovered or developed;
	•		drilling rigs and related equipment to explore for such reserves; and
	•		knowledgeable and experienced personnel to conduct all phases of oil and natural gas operations.

Oil and Natural Gas Regulations

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

	•		price controls;
	•		taxes; and
	•		environmental and other laws relating to the oil and natural gas industry.

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

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

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

•

the unitization of pooling of oil and natural gas properties;

	•		the establishment of maximum rates of production from oil and natural gas wells; and
	•		the regulation of spacing, plugging and abandonment of wells.

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

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

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

ITEM 1A. RISK FACTORS

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

Risks Related to Our Business

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

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

	•		the level of oil and natural gas prices, expectations about future oil and natural gas prices and the ability of international cartels to set and maintain production levels and prices;
	•		the cost of exploring for, producing and transporting oil and natural gas;
	•		the level and price of foreign oil and natural gas transportation;
	•		available pipeline and other oil and natural gas transportation capacity;
	•		weather conditions;
	•		international political, military, regulatory and economic conditions;
	•		the level of consumer demand;
	•		the price and the availability of alternative fuels;
	•		the effect of worldwide energy conservation measures; and
	•		the ability of oil and natural gas companies to raise capital.

Significant declines in oil and natural gas prices for an extended period may:

	•		impair our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;
	•		reduce the amount of oil and natural gas that we can produce economically;
	•		cause us to delay or postpone some of our capital projects;

	•		reduce our revenues, operating income and cash flow; and
	•		reduce the recorded value of our oil and natural gas properties.

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

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

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

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

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

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

	•		actual prices we receive for oil and natural gas;
	•		the amount and timing of actual production;
	•		supply and demand of oil and natural gas;
	•		limits of increases in consumption by natural gas purchasers; and
	•		changes in governmental regulations or taxation.

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

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

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

	•		seeking to acquire desirable producing properties or new leases for future exploration;
	•		marketing our oil and natural gas production;
	•		integrating new technologies; and
	•		seeking to acquire the equipment and expertise necessary to develop and operate our properties.

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

     Substantially all of our business activities are conducted through joint operating agreements under which we own partial interests in oil and natural gas wells.

     At December 31, 2006, we owned interests in 489 gross (376.42 net) oil and natural gas wells for which we were the operator and 936 gross (317.03 net) oil and natural gas wells where we were not the operator. Included in these wells are 383 gross (162.43 net) wells which are shut in or temporarily abandoned and 222 gross (120.61 net) injection wells.

     Whether or not we hold a majority working or operating interest in our oil and natural gas projects, 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. The failure of an operator of our wells to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore 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.

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

     Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as:

•

fires;

	•		natural disasters;
	•		explosions;
	•		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.

     We do not insure against the loss of oil or natural gas reserves as a result of operating hazards or insure against business interruption. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations.

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 bank 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 decreases as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to undertake or complete future drilling projects. We may, from time to time, seek additional financing, either in the form of increased bank borrowings, sale of debt or equity securities or other forms of financing and there can be no assurance as to the availability of any additional financing upon terms acceptable to us.

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

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

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

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

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.

If we default under either our revolving credit facility or our term loan facility, the lenders could foreclose on, and acquire control of, substantially all of our assets.

     The lenders under our two credit facilities have liens on substantially all of our assets. Additionally, both credit facilities restrict 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 these facilities. As a result of the liens held by our lenders, if we fail to meet our payment or other obligations under either 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 assets and liquidate those assets.

We are subject to many restrictions under our two credit facilities.

     As required by our revolving credit facility and term loan facility with our bank lenders, we have pledged substantially all of our producing oil and natural gas properties as collateral to secure the payment of our indebtedness. Both credit facilities restrict 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. Although we were in compliance with these covenants at December 31, 2006, 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. Our failure to comply with any of the restrictions and covenants under either credit facility could result in a default under both credit facilities, which could cause all of our existing indebtedness to be immediately due and payable.

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

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, at December 31, 2006, approximately 92% of the discounted present value of our proved reserves were located in the Permian Basin. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells due to mechanical problems, damages to the current producing reservoirs, significant governmental regulation, including any curtailment of production, or interruption of transportation of oil or natural gas produced from the wells.

Our derivative activities create a risk of financial loss.

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

	•		the counterparties to our future contracts fail to perform under the contract; or
	•		a sudden, unexpected event materially impacts oil or natural gas prices.

     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.

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

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

     We did not recognize an impairment in 2006. We cannot assure you that we will not experience ceiling test write-downs in the future.

Terrorist activities may adversely affect our business.

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

measures may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

We are highly dependent upon key personnel.

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

     We do not have employment agreements or long term contractual arrangements with any of our officers or other key employees. In periods of improving market conditions, our ability to obtain and retain qualified consultants on a timely basis may be adversely affected.

     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.

Our oil and natural gas operations are subject to many inherent 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:

	•		encountering unusual or unexpected formations and pressures;
	•		explosions, blowouts and fires;
	•		pipe and tubular failures and casing collapses;
	•		environmental pollution; and
	•		personal injuries.

     Any one of these potential hazards could result in accidents, environmental damage, personal injury, property damage and other harm that could result in substantial liabilities to us.

     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.

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 and a report by our independent auditors addressing these assessments. 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, investors could lose confidence in our reported financial information, and the price of our stock could decrease as a result.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

     Our revolving credit facility and second lien term loan facility contain a number of significant covenants that, among other things, restrict our ability to:

	•		dispose of assets;
	•		incur additional indebtedness;
	•		use our retained earnings and net income for payment of dividends on our common stock;
	•		create liens on our assets;
	•		enter into specified investments or acquisitions;
	•		repurchase, redeem or retire our capital stock or other securities;
	•		merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;
	•		engage in specified transactions with subsidiaries and affiliates; or
	•		engage in other specified corporate activities.

     Also, our credit facilities require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financing, make needed capital expenditures, withstand a future downturn in our business or 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 under the credit facilities impose on us. A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under the credit facilities. A default, if not cured or waived, could result in acceleration of all indebtedness outstanding under the credit facilities. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us.

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 our second lien term loan facility.

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

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

     On October 5, 2000, our Board of Directors adopted a stockholder rights plan. The plan is designed to protect Parallel from unfair or coercive takeover attempts and to prevent a potential acquirer from gaining control of Parallel without fairly compensating all of the stockholders. The plan authorized 50,000 shares of $0.10 par Series A Preferred Stock Purchase Rights. A dividend of one Right for each share of our outstanding common stock was distributed to stockholders of record at the close of business on October 16, 2000. If a public announcement is made that a person has acquired 15% or more of our common stock, or a tender or exchange offer is made for 15% of more of the common stock, each Right entitles the holder to purchase from the company one one-thousandth of a share of Series A Preferred Stock, at an exercise price of $26.00 per one one-thousandth of a share, subject to adjustment. In addition, under certain circumstances, the rights entitle the holders to buy Parallel’s stock at a 50% discount. We are authorized to issue 10.0 million shares of preferred stock; there are no outstanding shares as of December 31, 2006. 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 7.49% of the outstanding shares of our common stock as of February 15, 2007.

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 84% of our estimated future net revenues from our proved reserves at December 31, 2006 are from oil production, we will be more affected by movements in oil prices.

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.

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 developed and undeveloped oil and natural gas leases and the reserves associated with these 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.

Producing Wells and Acreage

     We have presented the table on the following page 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, 2006. 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)
Texas
Barnett Shale			—				—				21				6.69				1,150				363				18,037				4,765
Carm-Ann/M eans			90				74.85				—				—				5,560				4,843				235				235
Cook Mountain			—				—				14				1.39				1,044				238				74				33
Cotton Valley			—				—				1				0.13				40				5				9,365				968
Diamond M			97				64.03				—				—				5,805				3,809
Fullerton			151				127.86				—				—				3,683				3,155				—				—
Harris			65				54.72				—				—				1,179				1,044				2,586				2,484
Other Permian			243				34.94				27				11.74				23,079				15,469				280				280
Ganado Lake WI			8				4.80				5				3.00				12,732				5,958				—				—
Yegua/Frio/Wilcox			4				1.03				42				11.16				5,616				2,113				2,632				934
Total			658				362.23				110				34.11				59,888				36,997				33,209				9,699
Colorado			—				—				—				—				—				—				14,080				14,080
New Mexico			—				—				52				14.08				20,800				5,914				109,523				56,745
Utah			—				—				—				—				—				—				145,813				138,243
Total			658				362.23				162				48.19				80,688				42,911				302,625				218,767

     At December 31, 2006, we owned interests in 489 gross (376.42 net) oil and natural gas wells for which we were the operator and 936 gross (317.03 net) oil and natural gas wells where we were not the operator. Included in these wells are 383 (162.43 net) gross wells which are shut in or temporarily abandoned and 222 gross (120.61 net) injection wells.

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

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

Title to Properties

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

We do not believe that any of these encumbrances or burdens will materially affect our ownership or the use of our properties.

Oil and Natural Gas Reserves

     For the year ended December 31, 2006, our oil and natural gas reserves were estimated by Cawley Gillespie & Associates, Inc., Fort Worth, Texas.

     At December 31, 2006, our total estimated proved reserves were approximately 28.7 MMBbls of oil and approximately 58.9 Bcf of natural gas, or 38.5 MMBoe.

     The information in the following table provides you with certain information regarding our proved reserves as estimated by Cawley Gillespie & Associates, Inc. at December 31, 2006.

		Proved Developed				Proved Developed				Proved				Total
		Producing				Non-Producing				Undeveloped				Proved
						($ in thousands)
Oil (MBbls)			14,118				814				13,789				28,721
Gas (MMcf)			25,380				3,361				30,155				58,896
MBOE			18,348				1,374				18,815				38,537

     Estimates of our proved reserves and future net revenues are made using sales prices and costs, estimated to be in effect as of the date of our reserve estimates, that are held constant throughout the life of the properties, except to the extent a contract specifically provides for escalation of prices or costs. The average prices utilized in the estimation of our reserve calculations as of December 31, 2006 were $54.67 per Bbl of oil and $5.00 per Mcf of natural gas.

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

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

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

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

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

ITEM 3. LEGAL PROCEEDINGS

     On December 30, 2005, we were named as a defendant in a lawsuit filed in the 352nd Judicial District Court of Tarrant County, Texas, Cause No. 352-215616-05, AFE Oil and Gas, L.L.C. (aka AFE Oil and Gas, LLC)

v. Premium Resources II, L.P., Premium Resources, Inc., Danay Covert, Nick Morris, William D. Middleton, Dale Resources, L.L.C., and Parallel Petroleum, Inc.

     In this suit, the plaintiff alleges breach of fiduciary duty, fraud and conspiracy to defraud, breach of contract, constructive trust, suit to remove cloud from title, declaratory judgment, alter ego, tortious interference with contract and statutory fraud and seeks recovery of an unspecified amount of actual damages, special damages, consequential damages, exemplary damages, attorneys’ fees, pre-judgment and post-judgment interest and costs. Generally, the plaintiff alleges that it owns a 5.5% overriding royalty interest in certain oil and natural gas properties including the “Square Top LP” and the “West Fork LP” leases located in Tarrant County, Texas. The plaintiff alleges that the defendants (other than Dale Resources and Parallel) wrongfully and intentionally allowed these original oil and natural gas leases to terminate, causing the termination of plaintiff’s overriding royalty interest in each lease. The plaintiff further alleges that the defendants (other than Dale Resources and Parallel) failed to drill wells necessary to maintain the original leases in force and that after the original leases were allowed to terminate, the defendants (other than Dale Resources and Parallel) then acquired new oil and natural gas leases covering these same oil and natural gas properties, which were subsequently assigned to Dale Resources. Thereafter, Dale Resources allegedly assigned a portion of these new leases to Parallel.

     In addition to seeking unspecified monetary damages, the plaintiff also seeks to impose a constructive trust for its benefit on the new oil and natural gas leases and seeks a judicial declaration that either (1) the plaintiff is the owner of an overriding royalty interest in the new leases or that (2) the original leases and plaintiff’s interest in the original leases are still in effect. The plaintiff also claims that the new leases constitute a cloud on plaintiff’s title and seeks to have that cloud removed. Based on our present understanding of this case, we believe that we have substantial defenses to the plaintiff’s claims and intend to vigorously assert these defenses. However, if the plaintiff is awarded an interest in the new leases, we could potentially become liable for the payment to plaintiff of the portion of production proceeds attributable to plaintiff’s interest received by us. On the other hand, if the plaintiff prevails on its claim that the original leases are still in effect, our interest in the new leases could become subject to forfeiture. Based on the information known to date, we have not established a reserve for this matter.

     We are not aware of any other threatened material litigation and we have not 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 2006.

PART II

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

Market Information

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

		Price Per Share
		High				Low
2004
First Quarter		$	4.67			$	3.60
Second Quarter		$	5.35			$	3.83
Third Quarter		$	5.68			$	4.38
Fourth Quarter		$	5.60			$	4.83
2005
First Quarter		$	7.60			$	5.01
Second Quarter		$	9.00			$	6.26
Third Quarter		$	14.15			$	8.29
Fourth Quarter		$	18.52			$	11.41
2006
First Quarter		$	21.13			$	15.67
Second Quarter		$	25.56			$	18.47
Third Quarter		$	26.39			$	18.90
Fourth Quarter		$	20.96			$	16.34

     The closing price of our common stock on February 1, 2007 was $19.53 per share, as reported on the Nasdaq Global Market.

     As of February 1, 2007, there were approximately 2,446 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. The revolving credit facility and second lien term loan facility we have with our lenders prohibit the payment of dividends on our common stock. See “Risks Related to Our Business — We do not pay dividends on our common stock” on page 21.

Sale of Unregistered Securities

     At our annual meeting of stockholders held on June 22, 2004, the stockholders approved the Parallel Petroleum Corporation 2004 Non-Employee Director Stock Grant Plan. You can find a description of this plan on page 74. Historically, Director’s fees had been paid solely in cash. However, upon approval of the plan by the stockholders, we began paying an annual retainer fee to each non-employee Director in the form of common stock. Only Directors of Parallel who are not employees of Parallel or any of its subsidiaries are eligible to participate in the plan. Under the plan, each non-employee Director is entitled to receive an annual retainer fee consisting of shares of common stock that are automatically granted on the first day of July in each year, beginning on July 1, 2004. The actual number of shares received is determined by dividing $25,000 by the average daily closing price of the common stock on the Nasdaq Global Market for the ten consecutive trading days commencing fifteen trading days before

the first day of July of each year. On July 1, 2006, and in accordance with the terms of the plan, a total of 4,696 shares of common stock were granted to four non-employee Directors as follows: Jeffrey G. Shrader — 1,174 shares; Dewayne Chitwood — 1,174 shares; Martin B. Oring — 1,174 shares; and Ray M. Poage — 1,174 shares. The shares of common stock were issued without registration under the Securities Act of 1933, as amended, in reliance on the exemption provided by Section 4(2) of the Securities Act of 1933, as amended. Generally, shares issued under this plan are not transferable as long as the non-employee Director holding the shares remains a Director of Parallel.

     As further described under Item 13, Certain Relationships and Related Transactions, and Director Independence, on page 82 of this Annual Report on Form 10-K, Wealth Preservation, LLC, a financial consulting firm owned and managed by Martin B. Oring, a Director, exercised a warrant to purchase shares of our common stock on October 25, 2006. Utilizing a net exercise feature, Wealth Preservation LLC received 82,019 shares of common stock. No cash proceeds were received by us. The common stock was issued in reliance upon the exemptions from registration contained in Section 3(a)(9) and Section 4(2) of the Securities Act of 1933, as amended.

Repurchase of Equity Securities

     Neither we nor any “affiliated purchaser” repurchased any of our equity securities during the fourth quarter of the fiscal year ended December 31, 2006.

ITEM 6. SELECTED FINANCIAL DATA

     In the table below, we provide you with selected historical financial data. We have prepared this information using our audited Consolidated Financial Statements for the five-year period ended December 31, 2006. It is important that you read this data along with our audited Consolidated Financial Statements and related notes, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Item 7 below. The selected financial data provided are not necessarily indicative of our future results of operations or financial performance.

		Year Ended December 31,
		2006(1)				2005				2004				2003				2002(2)
		($ in thousands, except per share and per unit data)
Consolidated Income Statements Data:
Operating revenues		$	97,025			$	66,150			$	35,837			$	33,855			$	12,106
Operating expenses		$	56,606			$	32,805			$	23,571			$	21,138			$	11,250
Income (loss) before cumulative effect of change in accounting principle		$	26,155			$	(1,589	)		$	2,271			$	7,664			$	18,701
Net income (loss)		$	26,155			$	(1,589	)		$	2,271			$	7,602			$	18,701
Cumulative preferred stock dividend		$	—			$	(271	)		$	(572	)		$	(580	)		$	(585	)
Net income (loss) available to common stockholders		$	26,155			$	(1,860	)		$	1,699			$	7,022			$	18,116
Income (loss) per common share before cumulative effect of change in accounting principle
Basic		$	0.73			$	(0.06	)		$	0.07			$	0.33			$	0.88
Diluted		$	0.71			$	(0.06	)		$	0.07			$	0.31			$	0.79
Weighted average common stock and common stock equivalents outstanding
Basic			35,888				32,253				25,323				21,264				20,680
Diluted			36,756				32,253				25,688				24,175				23,549
Cash dividends — common stock		$	—			$	—			$	—			$	—			$	—
Consolidated Balance Sheet Data:
Total assets		$	442,818			$	253,008			$	170,671			$	118,343			$	102,351
Total liabilities		$	259,036			$	163,506			$	110,677			$	57,111			$	56,852
Long-term debt, less current maturities		$	165,000			$	100,000			$	79,000			$	39,750			$	45,604
Total stockholders’ equity		$	183,782			$	89,502			$	59,994			$	61,232			$	45,499

		Year Ended December 31,
		2006(1)				2005				2004				2003				2002(2)
		($ in thousands, except per share and per unit data)
Consolidated Statement of Cash Flow Data:
Cash provided by (used in)
Operating activities		$	74,186			$	37,118			$	18,156			$	19,493			$	1,528
Investing activities		$	(200,548	)		$	(84,949	)		$	(69,518	)		$	(15,494	)		$	(30,277	)
Financing activities		$	125,854			$	49,468			$	38,765			$	1,567			$	37,210
Operating Data:
Product Sales
Oil (Bbls)			1,137				923				729				629				131
Gas (Mcf)			6,539				3,592				2,690				3,356				2,670
BOE			2,227				1,522				1,177				1,188				576
Average sales price
Oil (per Bbl)		$	59.86			$	51.78			$	39.05			$	29.11			$	24.59
Gas (per Mcf)		$	6.19			$	8.54			$	5.85			$	5.40			$	3.33
Proved reserves
Oil (Bbls)			28,721				21,192				18,916				12,084				10,271
Gas (Mcf)			58,896				25,237				16,825				16,271				15,633

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

     The following discussion is intended to assist you in understanding our financial position and results of operations for each year in the three-year period ended December 31, 2006. You should read the following discussion and analysis in conjunction with our audited Consolidated Financial Statements and the related notes.

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

Overview and Strategy

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

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

	•		focuses on projects having less geologic risk;
	•		emphasizes acquisition, exploitation, development and enhancement activities;
	•		includes the utilization of horizontal and fracture stimulation technologies on certain types of reservoirs;

	•		focuses on acquiring producing properties; and
	•		expands the scope of operations by diversifying our exploratory and development efforts, both in and outside of our current areas of operation.

     We continue our efforts to maintain low general and administrative expenses relative to the size of our overall operations, utilize advanced technologies, serve as operator in appropriate circumstances, and reduce operating costs.

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

	•		the prices we receive for the oil and natural gas we produce;
	•		the results of reprocessing and reinterpreting our 3-D seismic data;
	•		the results of our drilling activities;
	•		the costs of obtaining high quality field services;
	•		our ability to find and consummate acquisition opportunities; and
	•		our ability to negotiate and enter into work to earn arrangements, joint venture or other similar agreements on terms acceptable to us.

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

Operating Performance

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

	•		seasonal demand;
	•		weather;
	•		hurricane conditions in the Gulf of Mexico;
	•		availability of pipeline transportation to end users;
	•		proximity of our wells to major transportation pipeline infrastructures; and
	•		world oil prices.

     Additional factors influencing our overall operating performance include:

	•		production expenses;
	•		overhead requirements; and
	•		costs of capital.

     Our oil and natural gas exploration, development and acquisition activities require substantial and continuing capital expenditures. Historically, the sources of financing to fund our capital expenditures have included:

	•		cash flow from operations;
	•		sales of our equity securities;
	•		bank borrowings; and
	•		industry joint ventures.

     Depletion per BOE in 2006 was $10.88, as compared to $7.61 in 2005 and $7.05 in 2004. The increase per BOE in 2006 was a result of increased drilling costs and recent acquisitions of producing properties.

Results of Operations

     As described under “Item 1. Business — About Our Strategy and Business”, we changed our business model in 2002. At the beginning of 2002, our total proved reserves were approximately 3.2 MMBoe with a reserves to production ratio of approximately 4 to 1. Through the execution of this business model, our reserves at the end of 2006 were approximately 38.5 MMBoe with a reserves to production ratio of approximately 17.3 to 1. As described on page 14 of this Annual Report on Form 10-K, the failure to replace oil and natural gas reserves may negatively affect our business. We monitor this risk by comparing the quantity of our oil and natural gas reserves at the end of each year to our production for that year. This comparison, which is made in the form of a reserves to production ratio, helps us measure our ability to offset produced volumes with new reserves that will be produced in the future. The reserves to production ratio is calculated by dividing the total proved reserves at the end of a year by the actual production for the same year. The annual change in this ratio provides us with an indication of our performance in replenishing annual production volumes. The reserves to production ratio is a statistical indicator that has limitations. The ratio is limited because it can vary widely based on the extent and timing of new discoveries and property acquisitions. In addition, the ratio does not take into account the cost or timing of future production of new reserves. For that reason, the ratio does not, and is not intended to, provide a measurement of value. At the end of 2002, our production was 77% natural gas and 23% oil, as compared to approximately 49% natural gas and 51% oil at the end of 2006. The production stream changed from shorter lived gulf coast natural gas to longer lived Permian Basin oil production and has increased our lease operating expense primarily due to increased utilities and chemicals associated with the operation of oil properties.

     The following table shows selected data and operating income comparisons for each of the three years ended December 31, 2006.

		Years Ended December 31,
		2006				2005				2004
		($ in thousands, except per unit data)
Production Volumes
Oil (Bbls)			1,137				923				729
Natural gas (Mcf)			6,539				3,592				2,690
BOE			2,227				1,522				1,177
Sales Price
Oil (per Bbl)(1)		$	59.86			$	51.78			$	39.05
Natural gas (per Mcf)(1)		$	6.19			$	8.54			$	5.85
BOE Price(1)		$	48.73			$	51.57			$	37.55
BOE Price(2)		$	43.56			$	43.46			$	30.45
Operating Revenues
Oil		$	68,076			$	47,800			$	28,455
Effect of oil hedges			(11,512	)			(12,139	)			(7,458	)
Natural gas			40,461				30,690				15,735
Effect of natural gas hedges			—				(201	)			(895	)
			97,025				66,150				35,837
Operating Expenses
Lease operating expense			16,819				9,947				7,373
Production taxes			5,577				4,102				2,108
General and administrative:
General and administrative			5,885				4,289				3,123
Public reporting			3,638				2,423				2,255
Depreciation, depletion and amortization			24,687				12,044				8,712
			56,606				32,805				23,571
Operating income		$	40,419			$	33,345			$	12,266

Critical Accounting Policies and Practices

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

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

     Depletion. Provision for depletion of oil and natural gas properties under the full cost method is calculated using the unit of production method based upon estimates of proved oil and natural gas reserves with oil and natural gas production being converted to a common unit of measurement based upon relative energy content. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. Oil and natural gas properties included $50.4 million and $22.3 million for 2006 and 2005, respectively, for unevaluated properties not included in depletion. The cost of any impaired property is transferred to the balance of oil and natural gas properties subject to depletion.

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

     The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. If future revisions significantly reduce previously estimated reserve quantities, it could result in a full cost ceiling write-down. At December 31, 2006, our ceiling was in excess of our capitalized costs. In addition to the impact of the estimates of proved reserves in calculating the ceiling test, estimates of proved reserves are also a significant component of the calculations of depreciation, depletion and amortization.

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

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

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

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

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

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

Years Ended December 31, 2006 and December 31, 2005

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

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

 

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

Costs and Expenses

														Percent
		Year Ended December 31,								Increase				Increase
		2006				2005				(Decrease)				(Decrease)
		($ in thousands)
Lease operating expense		$	16,819			$	9,947			$	6,872				69	%
Production taxes			5,577				4,102				1,475				36	%
General and administrative:
General and administrative			5,885				4,289				1,596				37	%
Public reporting			3,638				2,423				1,215				50	%
Total general and administrative			9,523				6,712				2,811				42	%
Depreciation, depletion and amortization			24,687				12,044				12,643				105	%
Total		$	56,606			$	32,805			$	23,801				73	%

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

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

     Total general and administrative expenses increased 42%, or $2.8 million, in 2006 over 2005. During the second quarter of 2006, we determined that stock options to purchase 30,000 shares of common stock had been granted in 2003 to four of our employees under our 1998 Stock Option Plan, but which were not available for issuance under the plan. In June 2006, the Board of Directors authorized us to enter into settlement and release agreements with the four employees. Under these agreements, we made a one-time lump sum cash payment to each employee in an amount equal to the “spread” between the exercise price of the options and the closing price of our stock on June 21, 2006. The total cash payments were approximately $511,000. This amount was charged to general and administrative expense during the second quarter of 2006. General and administrative expenses capitalized to the full cost pool were $1.7 million for 2006, compared to $1.3 million for 2005. On a BOE basis, general and administrative costs were $2.64 per BOE in 2006 compared to $2.82 per BOE in 2005, while public reporting costs were $1.63 per BOE and $1.59 per BOE for the same period.

     Included in our total general and administrative expenses are public reporting costs which increased 50%, or $1.2 million. Increased public reporting costs included, but were not limited to, increases in road show expenses, corporate counseling and oil and natural gas reserve analysis. In addition, we incurred additional public reporting costs associated with the stock options granted to our board of directors in late 2005.

     Depreciation and depletion expense increased 105% or $12.6 million for 2006 compared to 2005. Depletion per BOE was $10.88 for 2006 and $7.61 for 2005. This increase is attributable to increased drilling costs, recent producing property purchases and reserve revisions as a result of decreased natural gas prices. We anticipate fiscal year 2007 depletion costs will increase with increased production volumes.

Other income (expense)

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