Parallel Petroleum 10-Q 2007 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2007

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition period from                    to                    

Commission File Number 000-13305

PARALLEL PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

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

(432) 684-3727

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

     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. Yesþ Noo

     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 filerþ      Accelerated filero      Non-accelerated filero

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

     At November 1, 2007, 38,252,644 shares of the Registrant’s Common Stock, $0.01 par value, were outstanding.

INDEX

	Page No.
PART I. — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Reference is made to the succeeding pages for the following consolidated financial statements:
- Consolidated Balance Sheets as of September 30, 2007 (unaudited) and December 31, 2006		1
- Unaudited Consolidated Statements of Operations for the three months and nine months ended September 30, 2007 and 2006		2
- Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30, 2007 and 2006		3
- Unaudited Consolidated Statements of Comprehensive Income for the three months and nine months ended September 30, 2007 and 2006		4
- Notes to Consolidated Financial Statements		5
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.		17
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		38
ITEM 4. CONTROLS AND PROCEDURES		41
PART II. — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS		41
ITEM 1A. RISK FACTORS		41
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		46
ITEM 6. EXHIBITS		47
SIGNATURES
Certification of Principal Executive Officer - Section 302
Certification of Principal Financial Officer - Section 302
Certification of Chief Executive Officer - Section 906
Certification of Chief Financial Officer - Section 906

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PART I. — FINANCIAL INFORMATION

ITEM I. Financial Statements

PARALLEL PETROLEUM CORPORATION

Consolidated Balance Sheets

(dollars in thousands, except share data)

	September 30,			December 31,
	2007			2006
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	5,318		$	5,910
Accounts receivable:
Oil and natural gas sales		18,902			18,605
Joint interest owners and other, net of allowance for doubtful account of $50 and $80		3,507			7,209
Affiliates and joint ventures		3,335			3,338
		25,744			29,152
Other current assets		1,515			2,863
Deferred tax asset		6,514			4,340
Total current assets		39,091			42,265
Property and equipment, at cost:
Oil and natural gas properties, full cost method (including $72,435 and $50,375 not subject to depletion)		609,216			501,405
Other		2,839			2,614
		612,055			504,019
Less accumulated depreciation, depletion and amortization		(137,064	)		(115,513	)
Net property and equipment		474,991			388,506
Restricted cash		53			325
Investment in pipelines and gathering system ventures		8,621			6,454
Other assets, net of accumulated amortization of $1,386 and $760		2,820			5,268
	$	525,576		$	442,818
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	42,556		$	36,171
Asset retirement obligations		583			701
Derivative obligations		19,867			14,109
Total current liabilities		63,006			50,981
Revolving credit facility		89,000			115,000
Term loan		—			50,000
Senior notes (principal amount $150,000)		145,300			—
Asset retirement obligations		4,219			4,362
Derivative obligations		5,471			14,386
Deferred tax liability		28,493			24,307
Total long-term liabilities		272,483			208,055
Commitments and contingencies
Stockholders’ equity:
Series A preferred stock — par value $0.10 per share, authorized 50,000 shares		—			—
Common stock — par value $0.01 per share, authorized 60,000,000 shares, issued and outstanding 38,231,144 and 37,547,010		382			375
Additional paid-in capital		142,991			140,353
Retained earnings		46,714			43,054
Total stockholders’ equity		190,087			183,782
	$	525,576		$	442,818

The accompanying notes are an integral part of these Consolidated Financial Statements.

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PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Operations

(unaudited)

(in thousands, except per share data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Oil and natural gas revenues:
Oil and natural gas sales	$	29,487		$	29,490		$	79,957		$	82,360
Loss on hedging		—			(3,279	)		—			(9,264	)
Total revenues		29,487			26,211			79,957			73,096
Cost and expenses:
Lease operating expense		6,445			5,323			16,420			12,639
Production taxes		1,448			1,538			3,696			4,116
Production tax refund		—			—			(1,209	)		—
General and administrative		2,492			2,405			7,737			7,147
Depreciation, depletion and amortization		7,821			7,420			21,680			17,848
Total costs and expenses		18,206			16,686			48,324			41,750
Operating income		11,281			9,525			31,633			31,346
Other income (expense), net:
Gain (loss) on derivatives not classified as hedges		(4,556	)		10,323			(11,161	)		116
Gain on ineffective portion of hedges		—			305			—			500
Interest and other income		55			29			163			122
Interest expense		(5,429	)		(3,345	)		(13,449	)		(8,944	)
Cost of debt retirement		(760	)		—			(760	)		—
Other expense		(76	)		(96	)		(91	)		(164	)
Equity in loss of pipelines and gathering system ventures		(69	)		(39	)		(663	)		(68	)
Total other income (expense), net		(10,835	)		7,177			(25,961	)		(8,438	)
Income before income taxes		446			16,702			5,672			22,908
Income tax expense, deferred		(153	)		(5,706	)		(2,011	)		(7,837	)
Net income	$	293		$	10,996		$	3,661		$	15,071
Net income per common share:
Basic	$	0.01		$	0.30		$	0.10		$	0.43
Diluted	$	0.01		$	0.30		$	0.09		$	0.42
Weighted average common shares outstanding:
Basic		38,033			36,215			37,791			35,340
Diluted		38,767			36,919			38,806			36,027

The accompanying notes are an integral part of these Consolidated Financial Statements.

 

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PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2007 and 2006

(unaudited)

(dollars in thousands)

	2007			2006
Cash flows from operating activities:
Net income	$	3,661		$	15,071
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		21,680			17,848
Gain on sale of automobiles		(25	)		—
Accretion of asset retirement obligation		243			172
Accretion of senior notes discount		114			—
Deferred income tax		2,011			7,837
(Gain) loss on derivatives not classified as hedges		11,161			(116	)
Gain on ineffective portion of hedges		—			(500	)
Cost of debt retirement		760			—
Common stock issued in lieu of cash for directors fees		96			100
Stock option expense		161			435
Equity in loss of pipelines and gathering system ventures		663			68
Bad debt expense		(30	)		—
Changes in assets and liabilities:
Other assets, net		226			1,140
Restricted cash		272			(50	)
Decrease (increase) in accounts receivable		3,438			(12,084	)
Decrease (increase) in other current assets		713			(151	)
Increase in accounts payable and accrued liabilities		6,385			14,880
Federal tax deposit		—			(40	)
Net cash provided by operating activities		51,529			44,610
Cash flows from investing activities:
Additions to oil and natural gas properties		(110,015	)		(147,058	)
Use of restricted cash for acquisition of oil and natural gas properties		—			2,366
Proceeds from disposition of oil and natural gas properties and other property and equipment		1,711			130
Additions to other property and equipment		(340	)		(800	)
Settlements on derivative instruments		(9,875	)		(3,568	)
Investment in pipelines and gathering system ventures		(2,830	)		(9,688	)
Net cash used in investing activities		(121,349	)		(158,618	)
Cash flows from financing activities:
Borrowings from bank line of credit		68,500			90,000
Payments on bank line of credit		(94,500	)		(43,000	)
Payment on term loan		(50,000	)		—
Senior notes (principal amount $150,000)		145,186			—
Deferred financing cost		(2,346	)		(179	)
Proceeds (net) from common stock issued		—			60,315
Proceeds from exercise of stock options		2,388			766
Net cash provided by financing activities		69,228			107,902
Net decrease in cash and cash equivalents		(592	)		(6,106	)
Cash and cash equivalents at beginning of period		5,910			6,418
Cash and cash equivalents at end of period	$	5,318		$	312
Non-cash financing and investing activities:
Oil and natural gas properties asset retirement obligations	$	(505	)	$	1,957
Non-cash exchange of oil and natural gas properties
Properties received in exchange	$	6,463		$	—
Properties delivered in exchange	$	(5,495	)	$	—
Other transactions:
Interest paid	$	10,451		$	9,065

The accompany notes are an integral part of these Consolidated Financial Statements.

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PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Comprehensive Income

(unaudited)

(dollars in thousands)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007		2006			2007		2006
Net income	$	293	$	10,996		$	3,661	$	15,071
Other comprehensive loss:
Unrealized gain (loss) on derivatives		—		634			—		(1,750	)
Reclassification adjustments for losses on derivatives included in net income		—		3,240			—		9,191
Change in fair value of derivatives		—		3,874			—		7,441
Income tax expense		—		(1,317	)		—		(2,530	)
Total other comprehensive income		—		2,557			—		4,911
Total comprehensive income	$	293	$	13,553		$	3,661	$	19,982

The accompanying notes are an integral part of these Consolidated Financial Statements.

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PARALLEL PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. DESCRIPTION OF BUSINESS – NATURE OF OPERATIONS AND BASIS OF PRESENTATION

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

     Parallel is 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.

     The financial information included herein is unaudited. The balance sheet as of December 31, 2006 has been derived from our audited Consolidated Financial Statements as of December 31, 2006. The unaudited financial information includes all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for a fair statement of the results of operations for the interim periods. The results of operations for the interim period are not necessarily indicative of the results to be expected for an entire year. Certain 2006 amounts have been conformed to the 2007 financial statement presentation.

     Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in this Quarterly Report on Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission. These financial statements should be read in conjunction with the audited Consolidated Financial Statements and notes included in our Annual Report on Form 10-K/A for the year ended December 31, 2006.

     Unless otherwise indicated or unless the context otherwise requires, all references to “Parallel”, “we”, “us”, and “our” are to Parallel Petroleum Corporation and its consolidated subsidiaries, Parallel L.P. and Parallel, L.L.C.

     On July 12, 2007, our subsidiaries, Parallel L.P. and Parallel L.L.C., were merged with and into Parallel Petroleum Corporation.

NOTE 2. STOCKHOLDERS’ EQUITY

     Options

     We account for stock based compensation in accordance with the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards No. 123 (revised 2004),Share-Based Payment(SFAS 123(R)).

     For the nine months ended September 30, 2007 and 2006, we recognized compensation expense of approximately $161,000 and $493,000, respectively, with a tax benefit of approximately $55,000 and

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$168,000, respectively, associated with our stock option grants. During the second quarter of 2007, we revised our estimate of expected forfeitures of stock options granted to directors due to the resignation of a director and the subsequent forfeiture of 40,000 stock options held by him. As a result, we revised our estimate of the grant date fair value of shares expected to ultimately vest under our stock option plan by approximately $283,000. As a consequence, general and administrative expenses during the three months ended June 30, 2007 were reduced by approximately $154,000 which included a cumulative adjustment for amounts previously expensed associated with options estimated to be forfeited or surrendered.

     During the second quarter of 2006, we determined that stock options to purchase 30,000 shares of common stock, which were granted in 2003, were not available for grant under our existing stock option plans. In June 2006, these “excess” options were cancelled in exchange for our payment to four employees of cash totaling approximately $511,000. This amount was charged to expense during the second quarter of 2006.

     The following table presents future stock-based compensation expense expected to be recognized over the vesting period of:

	(in thousands)
Fourth quarter 2007		86
2008		228
2009 through 2011		122
Total	$	436

     Options to purchase a total of 137,500 shares of common stock were outstanding and unvested as of September 30, 2007. During the nine months ended September 30, 2007, options to purchase 17,500 shares of common stock were granted to one individual, options to purchase 597,000 shares of common stock were exercised and options to purchase 40,000 shares were forfeited and no options expired.

     The fair value of each option award is estimated on the date of grant. The fair values of stock options granted prior to and remaining outstanding at September 30, 2007 and that had option shares subject to future vesting at that date were determined using the Black-Scholes option valuation method and the assumptions noted in the following table. Expected volatilities are based on historical volatility of the stock. The expected term of the options granted used in the model represent the period of time that options granted are expected to be outstanding.

	2007			2005			2001
Expected volatility		52.52	%		54.20	%		57.95	%
Expected dividends		0.00			0.00			0.00
Expected term (in years)		6			7			8
Risk-free rate		4.89	%		4.20	%		5.05	%

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     A summary of the option activity as of September 30, 2007 is presented below:

						Weighted
						Average
						Remaining
				Weighted Average		Contractual		Aggregate
	Options			Exercise Price		Term		Intrinsic Value
	(in thousands)					(years)		(in thousands)
Outstanding December 31, 2006		1,199		$	5.40
Granted		17		$	22.89
Exercised		(597	)	$	4.00
Forfeited		(40	)	$	12.27
Outstanding September 30, 2007		579		$	6.90		6.1	$	5,844
Exercisable at September 30, 2007		442		$	5.30		5.2	$	5,163

	(in thousands)
Intrinsic Value of Options Exercised Nine Months Ended September 30, 2007	$	9,705
Intrinsic Value of Options Exercised Nine Months Ended September 30, 2006	$	2,855
Fair Market Value of Options Granted Nine Months Ended September 30, 2007	$	218
Fair Market Value of Options Granted Nine Months Ended September 30, 2006	$	—

     We have outstanding stock options granted under five separate plans. Generally, options expire 10 years from the date of grant and become exercisable at rates ranging from 10% each year up to 50% each year. The exercise price cannot be less than the fair market value per share of common stock on the date of grant.

NOTE 3. CREDIT ARRANGEMENTS

     In the past, we have maintained two separate credit facilities. One of these credit facilities is our Third Amended and Restated Credit Agreement, as amended, or “Revolving Credit Agreement”, with a group of bank lenders which, at September 30, 2007, provided us with a revolving line of credit having a “borrowing base” limitation of $150.0 million. The total amount that we can borrow and have outstanding at any one time is limited to the lesser of $350.0 million or the borrowing base established by the lenders. At September 30, 2007, the principal amount outstanding under our revolving credit facility was $89.0 million, excluding $445,000 reserved for our letters of credit. Our second credit facility was a five year term loan facility provided to us under a Second Lien Term Loan Agreement, or the “Second Lien Agreement”, with a group of banks and other lenders. The Second Lien Term Loan Agreement was paid off and terminated on July 31, 2007 with our payment to the lenders of $50.2 million, including interest. This payment was made with proceeds from our sale of unsecured senior notes, or “senior notes”, in the principal amount of $150.0 million that we completed on July 31, 2007.

     Revolving Credit Facility

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

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principal payments that may be required because of our outstanding loans being in excess of the borrowing base, interest only is payable monthly.

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

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

     The interest rate we are required to pay on our borrowings, including the applicable margin, may never be less than 5.00%. At September 30, 2007, our weighted average base rate and LIBOR rate, plus the applicable margin, was 7.64% on $89.0 million, the outstanding principal amount of our revolving loan on that same date.

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

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

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

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

     The Revolving Credit Agreement contains various restrictive covenants, including (i) maintenance of a minimum current ratio, (ii) maintenance of a maximum ratio of funded indebtedness to earnings before interest, income taxes, depreciation, depletion and amortization, (iii) maintenance of a minimum net worth, (iv) prohibition of payment of dividends and (v) restrictions on incurrence of additional debt. We have pledged substantially all of our producing oil and natural gas properties to secure the repayment of our indebtedness under the Revolving Credit Agreement.

     As of September 30, 2007 we were in compliance with all of the covenants in our Revolving Credit Agreement.

     Second Lien Term Loan Facility

     Until July 31, 2007, we also had a $50.0 million term loan made available to us under our Second Lien Agreement. Similar to our Revolving Credit Agreement, interest on loans made to us under this credit facility accrued, at our election, either at an alternate base rate or a rate designated in the Second Lien Agreement as the “LIBO” rate. The alternate base rate was the greater of (a) the prime rate in effect on any day and (b) the “Federal Funds Effective Rate” in effect on such day plus¹/2 of 1%, plus a margin of 3.50% per annum.

     The LIBO rate was generally equal to the sum of (a) a rate appearing in the Dow Jones Market

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Service for the applicable interest periods offered in one, two, three or six month periods and (b) an applicable margin rate per annum equal to 4.50%.

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

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

     Upon completion of our senior notes offering, we paid off and terminated this facility on July 31, 2007 with $50.2 million of the net proceeds from the offering. As a result we charged to earnings $760,000 of previously capitalized debt issuance cost.

     Senior Notes

     On July 31, 2007, we completed a private offering of unsecured senior notes (the “senior notes”) in the principal amount of $150.0 million. The senior notes were recorded at the principal amount net of underwriters discount and related expenses of $4.8 million. The senior notes mature on August 1, 2014 and bear interest at 10.25% which is payable semi-annually beginning on February 1, 2008. Considering the discount on the senior notes, the effective interest rate is 10.92%. Prior to August 1, 2010, we may redeem up to 35% of the senior notes for a price equal to 110.250% of the original principal amount of the senior notes with the proceeds of certain equity offerings. On or after August 1, 2011 we may redeem all or some of the senior notes at a redemption price that will decrease from 105.125% of the principal amount of the senior notes to 100% of the principal amount on August 1, 2013. In addition, prior to August 1, 2011, we may redeem some or all of the senior notes at a redemption price equal to 100% of the principal amount of the senior notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. Generally, the “make-whole” premium is an amount equal to the greater of (a) 1% of the principal amount of the senior notes being redeemed and (b) the excess of the present value of the redemption price of such notes as of August 1, 2011 plus all required interest payments due through August 1, 2011 (computed at a discount rate equal to a specified U.S. “Treasury Rate” plus 50 basis points), over the principal amount of the senior notes being redeemed.

     We have agreed, pursuant to a Registration Rights Agreement with the initial purchasers of the senior notes to use our commercially reasonable efforts to prepare and file with the Securities and Exchange Commission, within 180 days after July 31, 2007, a registration statement with respect to a registered offer to exchange freely tradable notes having substantially identical terms as the senior notes and to use our reasonable best efforts to cause the registration statement to be declared effective within 210 days after July 31, 2007. If we fail to meet these obligations under the Registration Rights Agreement we may be required to pay additional interest to holders of the senior notes. The rate of additional interest will be .25% per year for the first 90-day period immediately following a determination that the provisions of the Registration Rights Agreement have not been fulfilled, with the rate increasing by an additional .25% for each subsequent 90 day period up to a maximum additional interest rate of 1.0% per year. Under this agreement, the maximum additional interest that we could be required to pay over the life of the senior

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notes is approximately $9.4 million. No amounts of additional interest have been accrued as a liability as we have no belief that we will not be able to fulfill the requirements of the Registration Rights Agreement.

     The indenture governing the senior notes restricts our ability to: (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the senior notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business.

     The net proceeds, after payment of typical transaction expenses, of approximately $143.5 million were used first to retire our second lien term loan with the remainder being applied to our revolving credit facility.

     Interest Accrued

     For the nine months ended September 30, 2007, the aggregate interest accrued under our Revolving Credit Agreement, Second Lien Agreement and our senior notes was approximately $13.5 million. Of this amount, approximately $393,000 was capitalized.

NOTE 4. PROPERTY EXCHANGE

     On February 23, 2007, we entered into a property exchange agreement with an unrelated third party. As a result of the exchange, we acquired an additional 9,233 net undeveloped acres in our New Mexico Wolfcamp project area with an estimated fair value of approximately $6.5 million. We will be the operator of wells drilled on this undeveloped acreage. Under the terms of the exchange agreement, we assigned to the third party interests in 37 non-operated wells and 3,250 net undeveloped non-operated acres in the New Mexico Wolfcamp project area, along with cash of approximately $969,000. In accordance with the full cost method of accounting, no gain or loss was recorded on the transaction.

NOTE 5. FULL COST CEILING TEST

     We use the full cost method to account for our oil and natural gas producing activities. Under the full cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling limitation is the discounted estimated after-tax future net cash flows from proved oil and natural gas properties. The net book value of oil and natural gas properties, less related deferred income taxes is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less related deferred income taxes over the ceiling, is generally written off as an expense. Under rules and regulations of the SEC, the excess above the ceiling is not written off if, subsequent to the end of the quarter or year but prior to the release of the financial results, prices have increased sufficiently that such excess above the ceiling would not have existed if the increased prices were used in the calculations.

     Under the full cost method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including a portion of our overhead, are capitalized. In the nine month periods ended September 30, 2007 and 2006, overhead costs capitalized were approximately $1.1 million and $1.3 million, respectively.

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NOTE 6. DERIVATIVE INSTRUMENTS

General

     We enter into derivative contracts to provide a measure of stability in the cash flows associated with our oil and natural gas production and interest rate payments and to manage exposure to commodity price and interest rate risk. Our objective is to lock in a range of oil and natural gas prices and to limit variability in our cash interest payments. Our Revolving Credit Agreement requires us to maintain derivative financial instruments covering at least 50% of our estimated monthly production of oil and natural gas extending 24 months into the future.

     Derivative contracts not designated as cash flow hedges are “marked-to-market” at each period end and the increases or decreases in fair values recorded to earnings. No derivative instruments entered into subsequent to June 30, 2004 have been designated as cash flow hedges.

     We are exposed to credit risk in the event of nonperformance by the counterparty to these contracts, BNP Paribas and Citibank, N.A. However, we periodically assess the creditworthiness of the counterparty to mitigate this credit risk.

Interest Rate Sensitivity

     We completed a fixed interest rate swap contract with BNP Paribas, based on the 90-day LIBOR rates at the time we entered into the contract in January 2003. This interest rate swap was treated as a cash flow hedge as defined by Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (“SFAS 133”), and covered $10.0 million of our variable rate debt for all of 2006. As of December 31, 2006 this interest rate swap had expired.

     We have employed fixed interest rate swap contracts with BNP Paribas and Citibank, N.A. based on the 90-day LIBOR rates at the time of the contracts. These contracts are accounted for by “mark to market” accounting as prescribed in SFAS 133. We view these contracts as protection against future interest rate volatility. As of September 30, 2007, the fair market value of these interest rate swaps was a liability of approximately $591,000.

     The table below recaps the nature of these interest rate swaps and the fair market value of these contracts as of September 30, 2007.

						Estimated
	Notional		Fixed			Fair
Period of Time	Amounts		Interest Rates			Market Value
	($ in millions)					($ in thousands)
October 1, 2007 thru December 31, 2007	$	100		4.62	%	$	161
January 1, 2008 thru December 31, 2008	$	100		4.86	%		(323	)
January 1, 2009 thru December 31, 2009	$	50		5.06	%		(283	)
January 1, 2010 thru October 31, 2010	$	50		5.15	%		(146	)
Total Fair Market Value						$	(591	)

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Commodity Price Sensitivity

     All of our commodity derivatives are accounted for using “mark-to-market” accounting as prescribed in SFAS 133.

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

     A summary of our collar positions at September 30, 2007 is as follows:

							Estimated
	Barrles of		NyMex Oil Prices				Fair Market
Period of Time	Oil		Floor		Cap		Value
							($ in thousands)
October 1, 2007 thru December 31, 2007		73,600	$	55.63	$	84.88	$	(108	)
January 1, 2008 thru December 31, 2008		237,900	$	60.38	$	81.08		(553	)
January 1, 2009 thru December 31, 2009		620,500	$	63.53	$	80.21		(473	)
January 1, 2010 thru October 31, 2010		486,400	$	63.44	$	78.26		(80	)

			Houston Ship
	M M Btu of		Channel Gas Prices
	Natural Gas		Floor		Cap
October 1, 2007 thru October 31, 2007		31,000	$	6.00	$	11.05	—

	M M Btu of		WAHA Gas Prices
	Natural Gas		Floor		Cap
October 1, 2007 thru October 31, 2007		93,000	$	6.25	$	8.90		75
October 1, 2007 thru March 31, 2008		1,098,000	$	6.50	$	9.50		472
Total Fair Market Value							$	(667	)

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

     We have entered into oil swap contracts with BNP Paribas. A summary of our commodity swaps at September 30, 2007 is as follows:

					Estimated
	Number of		NyMex Oil		Fair Market
Period of Time	Barrels of Oil		Swap Price		Value
					($ in thousands)
October 1, 2007 thru December 31, 2007		119,600	$	34.36	$	(5,411	)
January 1, 2008 thru December 31, 2008		439,200	$	33.37		(17,923	)
Total fair market value					$	(23,334	)

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NOTE 7. NET INCOME PER COMMON SHARE

     Basic earnings per share (“EPS”) exclude any dilutive effects of options, warrants and convertible securities and is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed similar to basic earnings per share. However, diluted earnings per share reflect the assumed conversion of all potentially dilutive securities.

     The following table provides the computation of basic and diluted earnings per share for the three and nine months ended September 30, 2007 and 2006:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
	(dollars in thousands, except per share data)
Basic EPS Computation:
Numerator-
Income	$	293	$	10,996	$	3,661	$	15,071
Denominator-
Weighted average common shares outstanding		38,033		36,215		37,791		35,340
Basic EPS:
Income per share	$	0.01	$	0.30	$	0.10	$	0.43
Diluted EPS Computation:
Numerator-
Income	$	293	$	10,996	$	3,661	$	15,071
Denominator -
Weighted average common shares outstanding		38,033		36,215		37,791		35,340
Employee stock options		521		596		749		581
Warrants		213		108		266		106
Weighted average common shares for diluted earnings per share assuming conversion		38,767		36,919		38,806		36,027
Diluted EPS:
Income per share	$	0.01	$	0.30	$	0.09	$	0.42

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NOTE 8. ASSET RETIREMENT OBLIGATIONS

     The following table summarizes our asset retirement obligation transactions:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007			2006		2007			2006
				(in thousands)
Beginning asset retirement obligation	$	4,842		$	4,420	$	5,063		$	2,495
Additions related to new properties		85			123		151			314
Revisions in estimated cash flows		(130	)		11		(297	)		1,674
Deletions related to property disposals		(74	)		—		(358	)		(30	)
Accretion expense		79			71		243			172
Ending asset retirement obligation	$	4,802		$	4,625	$	4,802		$	4,625

NOTE 9. RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS

     We adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109” (“FIN 48”), on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement 109, “Accounting for Income Taxes”, and prescribes a recognition threshold and measurement process for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

     Based on our evaluation, we have concluded that there are no significant uncertain tax positions requiring recognition in our financial statements. Our evaluation was performed for the tax years ended December 31, 2003, 2004, 2005 and 2006, the tax years which remain subject to examination by major tax jurisdictions as of September 30, 2007.

     We may from time to time be assessed interest or penalties by major tax jurisdictions, although any such assessments historically have been minimal and immaterial to our financial results.

     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“FAS 157”). FAS 157 defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosure requirements related to the use of fair value measures in financial statements. FAS 157 will be effective for our financial statements for the fiscal year beginning January 1, 2008; however, earlier application is encouraged. We are currently evaluating the timing of adoption and the impact that adoption might have on our financial position or results of operations.

     In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of FASB Statement No. 115,” (FAS 159) which will become effective on January 1, 2008. FAS 159 permits entities to measure eligible financial assets, financial liabilities and firm commitments at fair value, on an instrument-by-instrument basis, that are otherwise not permitted to be accounted for at fair value under other generally accepted accounting principles. The

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fair value measurement election is irrevocable and subsequent changes in fair value must be recorded in earnings. We will adopt this statement in the first quarter of 2008 and we do not expect to elect the fair value option for any eligible financial instruments and other items.

NOTE 10. INVESTMENT IN GAS GATHERING SYSTEMS

     We have invested in three separate partnerships that own and construct pipeline systems for gathering natural gas, primarily on our leaseholds in the Barnett Shale area. These partnerships include West Fork Pipeline Company I, L.P., West Fork Pipeline Company II, L.P. and West Fork Pipeline Company V, L.P. These investments were recorded as equity investments in the accompanying consolidated balance sheet. During the fourth quarter 2006, substantially all of the assets of West Fork Pipeline I and West Fork Pipeline V were sold. As of September 30, 2007, we had invested $306,000 in West Fork Pipeline II. West Fork Pipeline II is currently acquiring the necessary easements and permits to begin transmission of natural gas.

     As of September 30, 2007, we also invested $8.3 million in a joint venture known as the Hagerman Gas Gathering System (“Hagerman”) to construct pipelines on certain of our leaseholds in New Mexico. The Hagerman gathering system is currently being extended to additional productive areas.

     Our current investment percentage in the two remaining ventures is as follows:

West Fork Pipeline Company II, L.P.	35.8750	%
Hagerman Gas Gathering System	76.5000	%

     Our investment in Hagerman is accounted for by the equity method since we do not have voting control. All significant actions taken by Hagerman must be approved by Parallel, plus one of the two other equity owners. Consequently, the remaining equity owners can prevent voting control by Parallel.

     Our equity investments consisted of the following as of the dates indicated:

	September 30,		December 31,
	2007		2006
	($ in thousands)
West Fork Pipeline Company II, L.P.	$	306	$	280
Hagerman Gas Gathering System		8,315		6,174
	$	8,621	$	6,454

     Our losses from equity investments were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	($ in thousands)						($ in thousands)
West Fork Pipeline Company I, L.P.	$	—		$	169		$	—		$	195
West Fork Pipeline Company II, L.P.		—			(15	)		5			(35	)
West Fork Pipeline Company V, L.P.		—			(22	)		—			(57	)
Hagerman Gas Gathering System		(69	)		(171	)		(668	)		(171	)
										��
	$	(69	)	$	(39	)	$	(663	)	$	(68	)

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     Summarized combined financial information for our equity investments (listed above) is reported below. Amounts represent 100% of the investees’ financial information:

	September 30,		December 31,
	2007		2006
	($ in thousands)
Balance Sheet
Current assets	$	601	$	1,408
Non-current assets		11,032		8,351
Current liabilities		541		1,329
Owners’ equity		11,092		8,430

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	($ in thousands)						($ in thousands)
Income Statement
Revenues	$	181		$	1,276		$	346		$	2,383
Costs and expenses		(426	)		(963	)		(1,234	)		(1,971	)
Net income (loss)	$	(245	)	$	313		$	(888	)	$	412

NOTE 11. COMMITMENTS AND CONTINGENCIES

     From time to time, we are party to ordinary routine litigation incidental to our business. We are not presently a defendant in any judicial or other proceedings, nor are we aware of any threatened litigation and we have not been a party to any bankruptcy, receivership, reorganization, adjustment or similar proceeding.

     Effective January 1, 2005, we established a 401(k) Plan and Trust for eligible employees. Employees may not participate in the former SEP plan with the establishment of the 401(k) Plan and Trust. As of the fiscal quarters ended September 30, 2007 and 2006, Parallel had made contributions to the 401(k) Plan and Trust of approximately $201,000 and $170,000, respectively.

     On May 21, 2007, we received a Notice of Proposed Adjustment, or the “Notice”, from the Internal Revenue Service, or the “Service”, advising us of proposed adjustments to our calculations of federal income tax resulting in a proposed alternative minimum tax liability in the aggregate amount of approximately $2.0 million for the years 2004 and 2005. After advising the Service that we intended to appeal the Notice, we received correspondence from the Service on July 10, 2007 stating that the issue remains in development pending receipt of additional documents requested and any proposed tax adjustment would not be made until after reviewing the documents requested. On November 5, 2007, we received an examination report related to this matter which reduces the amount of proposed adjustment to approximately $1.1 million, which includes interest. We intend to vigorously contest the adjustment proposed by the Service and believe that we will ultimately prevail in our position. We would expect the recording of any adjustment, if later determined to be required, to entail a reclassification from our deferred tax liability accounts to a current liability for federal income taxes payable. Such an adjustment would generally not result in a charge to earnings except for amounts which might be assessed for penalties or interest on underpayment

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of current tax for our fiscal years ending December 31, 2004 and 2005. If a liability for penalties or interest were determined to be probable, the amounts of such penalties and/or interest would be charged to earnings. We believe that the effects of this matter would not have a material adverse effect on our financial position or results of operations for any fiscal year, but could have a material adverse effect on our results of operations for the fiscal quarter in which we actually incur or establish a reserve account for penalties or interest.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

     The following discussion and analysis should be read in conjunction with management’s discussion and analysis contained in our 2006 Annual Report on Form 10-K/A, as well as the unaudited consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

OVERVIEW

Strategy

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

     Accelerate Horizontal Drilling and Fracture Stimulation Activities in Gas Resource Plays.We believe the use of horizontal drilling and fracture stimulations has enabled us to develop reserves economically, such as our Barnett Shale and Wolfcamp Carbonate gas projects.

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

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

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

     The extent to which we are able to implement and follow through with our business strategy 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 the oil and natural gas we produce, 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 our production volumes. 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

• to a lesser extent, world oil prices.

     Additional factors influencing our overall operating performance include:

• production expenses;

• overhead requirements;

• costs of capital; and

• effects of derivative contracts.

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     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 and debt securities;

• bank borrowings; and

• industry joint ventures.

     For the three months ended September 30, 2007 the sale price we received for our crude oil production (excluding hedges) averaged $69.45 per barrel compared with $64.53 per barrel for the three months ended September 30, 2006. The average sales price we received for natural gas for the three months ended September 30, 2007, was $5.81 per Mcf compared with $5.64 per Mcf for the three months ended September 30, 2006. Hedge costs for oil were $3.3 million for the three months ended September 30, 2006. The ineffective portion showed a gain of approximately $305,000 for the three months ended September 30, 2006. We settled all remaining derivatives classified as cash flow hedges in December 2006. Therefore, no ineffectiveness on hedges was identified in 2007. For information regarding prices received including our hedges, you should refer to the selected operating data table under “Results of Operations” on page 20.

     For the nine months ended September 30, 2007, the sale price we received for our crude oil production (excluding hedges) averaged $59.98 per barrel compared with $61.88 per barrel for the nine months ended September 30, 2006. The average sales price we received for natural gas for the nine months ended September 30, 2007, was $6.14 per Mcf compared with $6.11 per Mcf for the nine months ended September 30, 2006. Hedge costs for oil and natural gas was $9.3 million for the nine months ended September 30, 2006. The ineffective portion showed a gain approximately $500,000 for the nine months ended September 30, 2006. We settled all remaining derivatives classified as cash flow hedges in December 2006. Therefore, no ineffectiveness on hedges was identified in 2007. For information regarding prices received including our hedges, you should refer to the selected operating data table under “Results of Operations” on page 20.

     Our oil and natural gas producing activities are accounted for using the full cost method of accounting. Under this accounting method, we capitalize all costs incurred in connection with the acquisition of oil and natural gas properties and the exploration for and development of oil and natural gas reserves. These costs include lease acquisition costs, geological and geophysical expenditures, costs of drilling productive and non-productive wells, and overhead expenses directly related to land and property acquisition and exploration and development activities. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss recognized unless a disposition involves a material change in reserves, in which case the gain or loss is recognized.

     Depletion of the capitalized costs of oil and natural gas properties, including estimated future development costs, is provided using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Unproved oil and natural gas properties are not amortized, but are individually assessed for impairment. The cost of any impaired property is transferred to the balance of oil and natural gas properties being depleted. Depletion per BOE through September 30, 2007 and 2006 was $12.84 and $10.53 respectively.

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Results of Operations

     Our business activities are characterized by frequent, and sometimes significant, changes in our:

• reserve base;

• sources of production;

• product mix (gas versus oil volumes); and

• the prices we receive for our oil and natural gas production.

     Year-to-year or other periodic comparisons of the results of our operations can be difficult and may not fully and accurately describe our condition. The following table shows selected operating data for each of the three and nine months ended September 30, 2007 and September 30, 2006.

	Three Months Ended					Nine Months Ended
	9/30/2007		9/30/2006			9/30/2007			9/30/2006
			(in thousands, except per unit data)
Production Volumes:
Oil (Bbls)		254		282			797			848
Natural gas (Mcf)		2,043		2,001			5,243			4,894
BOE(1)		595		616			1,671			1,664
BOE per day		6.5		6.7			6.1			6.1
Sales Prices:
Oil (per Bbl)(2)	$	69.45	$	64.53		$	59.98		$	61.88
Natural gas (per Mcf)	$	5.81	$	5.64		$	6.14		$	6.11
BOE price(2)	$	49.62	$	47.91		$	47.86		$	49.50
BOE price(3)	$	49.62	$	42.58		$	47.86		$	43.93
Operating Revenues
Oil	$	17,619	$	18,194		$	47,786		$	52,478
Oil hedge		—		(3,279	)		—			(9,264	)
Natural gas		11,868		11,296			32,171			29,882
											��
	$	29,487	$	26,211		$	79,957		$	73,096
Operating Expenses:
Lease operating expense	$	6,445	$	5,323		$	16,420		$	12,639
Production taxes		1,448		1,538			3,696			4,116
Production tax refund		—		—			(1,209	)		—
General and administrative		2,492		2,405			7,737			7,147
Depreciation, depletion and amortization		7,821		7,420			21,680			17,848
	$	18,206	$	16,686		$	48,324		$	41,750
Operating income	$	11,281	$	9,525		$	31,633		$	31,346

(1)	A BOE means one barrel of oil equivalent using the ratio of six Mcf of gas to one barrel of oil.
(2)	Unhedged price is the actual price received at the wellhead for our oil.
(3)	Hedged price is the actual price received at the wellhead for our oil and natural gas plus or minus the settlements on our cash flow hedges.

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RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2007 AND 2006:

     Our oil and natural gas revenues and production product mix are displayed in the following table for the three months ended September 30, 2007 and September 30, 2006.

Oil and Gas Revenues

	Revenues(1)						Production
	2007			2006			2007			2006
Oil (Bbls)		60	%		57	%		43	%		46	%
Natural gas (Mcf)		40	%		43	%		57	%		54	%
Total		100	%		100	%		100	%		100	%

(1) Includes hedge transactions

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

	Three Months Ended September 30,					Increase			% Increase
	2007		2006			(Decrease)			(Decrease)
			(in thousands except per unit data)
Production Volumes
Oil (Bbls)		254		282			(28	)		(10	)%
Natural gas (Mcf)		2,043		2,001			42			2	%
BOE		595		616			(22	)		(3	)%
BOE/Day		6.5		6.7			(0.2	)		(3	)%
Sales Price
Oil (per Bbl)(1)	$	69.45	$	64.53		$	4.92			8	%
Natural gas (per Mcf)	$	5.81	$	5.64		$	0.17			3	%
BOE price(1)	$	49.62	$	47.91		$	1.71			4	%
BOE price(2)	$	49.62	$	42.58		$	7.04			17	%
Operating Revenues
Oil	$	17,619	$	18,194		$	(575	)		(3	)%
Oil hedges		—		(3,279	)		3,279			(100	)%
Natural gas		11,868		11,296			572			5	%
Total	$	29,487	$	26,211		$	3,276			12	%

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

Oil revenues

     Average oil prices, excluding hedges, for the three months ended September 30, 2006 were $64.53, as compared to $69.45 for the three months ended September 30, 2007. Average oil prices were up $4.92 Bbl. When applied to current production, this accounts for an additional $1.2 million in revenue. Oil production decreased 10% or 28,000 Bbls. These decreases occurred primarily in the Carm-Ann of 11,000 Bbls, Diamond M Deep of 11,000 Bbls and the Wilcox area in south Texas of 4,000 Bbls. These decreases were as a result of natural declines and limited developmental activity occurring in 2007 in these areas. The volume decline accounted for a reduction of $1.8 million in revenue.

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Natural gas revenues

     Average natural gas prices for three months ended September 30, 2006 was $5.64 compared to the three months ended September 30, 2007 of $5.81. Average natural gas prices received were up $0.17 per Mcf, when applied to current production this accounted for an increase of approximately $347,000 in revenue. Natural gas production increased 2%, primarily due to an increase in the New Mexico Wolfcamp of approximately 412,000 Mcf. This was as of a result of the developmental program in this area. This volume increase was offset with decreases in south Texas of approximately 302,000 Mcf which is as a result of normal decline and Parallel refocusing activity away from this area. In addition there was a decline of approximately 45,000 Mcf in the Permian area where limited developmental drilling activity has occurred during 2007. This volume increase accounted for an increase in revenue of approximately $225,000.

Oil hedges

     We settled all remaining derivatives classified as cash flow hedges in December 2006. Therefore, oil hedge losses were $0 for three months ended September 30, 2007 compared to a loss of $3.2 million for three months ended September 30, 2006.

Cost and Expenses

	Three months ended September 30,				Increase			% Increase
	2007		2006		(Decrease)			(Decrease)
			(dollars in thousands)
Lease operating expense	$	6,445	$	5,323	$	1,122			21	%
Production taxes		1,448		1,538		(90	)		(6	)%
General and administrative		2,492		2,405		87			4	%
Depreciation, depletion and amortization		7,821		7,420		401			5	%
Total	$	18,206	$	16,686	$	1,520			9	%

Lease operating expense

     Lease operating expenses are up primarily due to workover expenditures incurred in 2007. We are currently performing workovers on several of our older oil properties and this has led to an increase in this category of approximately $610,000. As we begin our drilling program on these oil properties, we expect these costs to go down. In addition we incurred approximately $691,000 in charges on new wells during the third quarter 2007 that had not been drilled in 2006. As we drill additional wells our lease operating expenses will go up. Lifting costs (excluding production taxes) were $10.84 per BOE in 2007 compared to $8.64 per BOE in 2006, a 25% increase in our per BOE lifting costs.

Production taxes

     Production taxes decreased 6% or $90,000 in 2007, associated with an approved reduced tax rate on non-operated wells in the Wilcox area of south Texas. We were notified of these rates in June 2007. Production taxes are a function of product mix, production volumes and product prices.

General and administrative

     General and administrative expenses increased 4%, or approximately $87,000, in 2007 as compared to 2006. This increase was primarily due to increases in legal fees of approximately $150,000. Salary costs were up $86,000 which offset a reduction in contract labor costs of $105,000. On a BOE basis, general and administrative expenses were $4.20 per BOE in 2007 compared to $3.90 per BOE in 2006.

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Depreciation, depletion and amortization

     Depreciation, depletion and amortization expense increased 5%, or $401,000, for 2007 as compared to 2006. This increase is attributable to an overall increase in actual and anticipated drilling costs and related oilfield service costs. Increased cost levels affect both the depletable amounts of capitalized costs in 2007 and the depletion attributable to amounts of estimated future development costs on proved undeveloped properties. Throughout 2007, our actual drilling activity and a majority of our newly identified proved undeveloped locations have been in our natural gas resource projects in the Permian Basin of west Texas and the Barnett Shale areas. These areas have higher associated per BOE drilling and development costs due to the use of horizontal drilling and multi-stage stimulation techniques. These factors, when combined with the increase in the absolute level of our capital expenditures during this time period have led to increases in our depletion rate per BOE.

Other income (expense)

	Three months ended September 30,						Increase			% Increase
	2007			2006			(Decrease)			(Decrease)
				(dollars in thousands)
Gain (loss) on derivatives not classified as hedges	$	(4,556	)	$	10,323			(14,879	)		(144	)%
Gain on ineffective portion of hedges		—			305			(305	)		(100	)%
Interest and other income		55			29			26			90	%
Interest expense, net		(5,429	)		(3,345	)		(2,084	)		62	%
Cost of debt retirement		(760	)		—			(760	)		N/A
Other expense		(76	)		(96	)		20			(21	)%
Equity in loss of pipelines and gathering system ventures		(69	)		(39	)		(30	)		77	%
Total	$	(10,835	)	$	7,177		$	(18,012	)		(251	)%

Gain (loss) on derivatives not classified as hedges

     We recorded a loss of $4.6 million in 2007 for derivatives not classified as hedges, as compared to a gain of $10.3 million for 2006. Future gains or losses on derivatives not classified as hedges will be impacted by the volatility of commodity prices and interest rates, as well as by the terms of any new derivative contracts.

Interest expense

     Interest expense increased $2.0 million with the $92 million increase in principal amount of our debt from $147.0 million at September 30, 2006 to $239.0 million at September 30, 2007 along with an increase in our weighted average interest rates for 2007.

Cost of debt retirement

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

Equity in loss of pipelines and gathering system ventures

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

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gas gathering system in New Mexico. For the quarter ended September 30, 2007, the loss from the investment was approximately $69,000. This loss was offset by an insignificant amount of income from our equity investment in West Fork Pipeline II. We recognize our share of net loss from negative net operating income as an investment loss.

Federal income tax

     Federal income tax expense was approximately $153,000 in 2007 compared to $5.7 million in 2006. Income tax expense for 2007 will be dependent on our earnings and is expected to be approximately 35% of income before income taxes.

Basic and diluted net income

     We had basic and diluted net income per share of $0.01 and $.30 for 2007 and 2006, respectively. Basic weighted average common shares outstanding increased from 36.2 million shares in 2006 to 38.0 million shares in 2007. The increase in common shares was primarily due to our public offering of 2.5 million shares of common stock in August 2006 and the exercise of employee and non-employee stock options.

RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2007 AND 2006:

     Our oil and natural gas revenues and production product mix are displayed in the following table for the nine months ended September 30, 2007 and September 30, 2006.

Oil and Gas Revenues

	Revenues(1)						Production
	2007			2006			2007			2006
Oil (Bbls)		60	%		59	%		48	%		51	%
Natural gas (Mcf)		40	%		41	%		52	%		49	%
Total		100	%		100	%		100	%		100	%

(1) Includes hedge transactions

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

	Nine Months Ended September 30,					Increase			% Increase
	2007		2006			(Decrease)			(Decrease)
			(in thousands except per unit data)
Production Volumes
Oil (Bbls)		797		848			(51	)		(6	)%
Natural gas (Mcf)		5,243		4,894			349			7	%
BOE		1,671		1,664			7			0	%
BOE/Day		6.1		6.1			—			0	%
Sales Price
Oil (per Bbl)(1)	$	59.98	$	61.88		$	(1.90	)		(3	)%
Natural gas (per Mcf)	$	6.14	$	6.11		$	0.03			0	%
BOE price(1)	$	47.86	$	49.50		$	(1.64	)		(3	)%
BOE price(2)	$	47.86	$	43.93		$	3.93			9	%
Operating Revenues
Oil	$	47,786	$	52,478			(4,692	)		(9	)%
Oil hedges		—		(9,264	)		9,264			(100	)%
Natural gas		32,171		29,882			2,289			8	%
Total	$	79,957	$	73,096		$	6,861			9	%

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

Oil revenues

     Average wellhead realized crude oil prices decreased $1.90 per Bbl, or 3%, to $59.98 per Bbl for 2007, as compared to 2006. This price decrease caused our revenues to go down by approximately $1.5 million in 2007, as compared to 2006. Oil production decreased 6% attributable to a decline of approximately 35,000 Bbls, 31,000 Bbls and 28,000 Bbls in the Diamond M Deep, Carm-Ann and south Texas area, respectively comparing the nine months ended September 30, 2007 to nine months ended 2006. These decreases were as a result of natural declines and limited developmental activity occurring. We are currently refocusing our efforts away from the south Texas area. These decreases were partially offset with increases in the Harris field where we benefited from our development program in 2006. The decrease in oil production decreased revenue approximately $3.2 million for 2007.

Natural gas revenues

     Average realized wellhead natural gas prices received were up slightly to $6.14 per Mcf for the nine months ended September 30, 2007 from $6.11 per Mcf received for the nine months ended September 30, 2006. This slight price increase accounted for an increase in revenue of approximately $200,000. Natural gas production increased 7% primarily due to new wells in New Mexico Wolfcamp area where volumes were up 1.3 million Mcf and the Barnett Shale area where volumes were up approximately 260,000 Mcf offset by a decline of approximately 1.1 million Mcf in our south Texas wells comparing nine months ended September 30, 2007 to nine months ended 30, 2006. The increase in natural gas volumes increased revenue approximately $2.1 million for 2007.

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Oil hedges

     We settled all remaining derivatives classified as cash flow hedges in December 2006. Therefore, oil hedge losses were $0 in 2007 compared to a loss of approximately $9.3 million in 2006. On a BOE basis, hedges accounted for a realized loss of $5.57 per BOE in 2006.

Cost and Expenses

	Nine months ended September 30,					Increase			% Increase
	2007			2006		(Decrease)			(Decrease)
				(dollars in thousands)
Lease operating expense	$	16,420		$	12,639	$	3,781			30	%
Production taxes		3,696			4,116		(420	)		(10	)%
Production tax refund		(1,209	)		—		(1,209	)		N/A
General and administrative		7,737			7,147		590			8	%
Depreciation, depletion and amortization		21,680			17,848		3,832			21	%
Total	$	48,324		$	41,750	$	6,574			16	%

Lease operating expense

     Lease operating expenses are primarily higher due to new wells being put on line. Of the $3.8 million increase, $2.3 million of these charges are on wells that have been completed in the past year or completed late in the year during 2006; therefore costs are higher for the nine months ended September 30, 2007 compared to the same period 2006. Well repair and workover expenses increased approximately $1.5 million to $2.4 million for the nine months ended September 30, 2007 compared to approximately $900,000 for the nine months ended September 30, 2006. This is as a result of higher overall costs for such items and as we have refocused our efforts on lease maintenance and away from developmental activity during 2007 on our oil properties. Lifting costs (excluding production taxes) were $9.83 per BOE in 2007 compared to $7.60 per BOE in 2006.

Production taxes

     Production taxes decreased 10% or $420,000 in 2007. The decrease is a result of a reduction of our oil production during 2007 compared to 2006. Production taxes in the future periods will be a function of product mix, production volumes and product prices.

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

General and administrative

     General and administrative expenses increased 8%, or approximately $590,000, in 2007 as compared to 2006. This increase is due primarily to consulting and legal fees associated with accounting and other public reporting requirements. These associated costs were up $674,000. Also, higher salary expenses of $365,000 associated with a larger staff and increased salary rates were incurred in 2007. In addition, insurance premiums increased that we pay for our directors and officers insurance. As a result, we incurred additional expenditures of $104,000 for this insurance. Finally, we reduced the amount of capitalized general and administrative expenses during 2007 by $230,000 from $1.3 million to $1.1 million.

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     The above general and administrative increases were partially offset by decreases in bonus expenditures and stock option expenses. During the second quarter of 2006, we determined that stock options to purchase 30,000 shares of common stock, which were granted in 2003, were not available for grant under our existing stock option plans. In June 2006, these “excess” options were cancelled in exchange for our payment to four employees of cash totaling approximately $511,000. This amount was charged to expense during the second quarter 2006. During the second quarter of 2007, we revised our estimates of expected forfeitures of stock options granted to directors due to the resignation of a director and the subsequent forfeiture of 40,000 stock options held by him. As a result, we revised our estimate of the grant date fair value of shares expected to ultimately vest under our stock option plan by approximately $283,000.

Depreciation, depletion and amortization

     Depreciation, depletion and amortization expense increased 21%, or $3.8 million, for 2007 as compared to 2006. Depletion per BOE was $12.84 for 2007 and $10.53 for 2006. This increase is attributable to an overall increase in actual and anticipated drilling costs and related oilfield service costs. Increased cost levels affect both the depletable amounts of capitalized costs in 2007 and the depletion attributable to amounts of estimated future development costs on proved undeveloped properties. Throughout 2007, our actual drilling activity and a majority of our newly identified proved undeveloped locations have been in our natural gas resource projects in the Permian Basin of west Texas and the Barnett Shale areas. These areas have higher associated per BOE drilling and development costs due to the use of horizontal drilling and multi-stage stimulation techniques. These factors, when combined with the increase in the absolute level of our capital expenditures during this time period have led to a significant increase in our depletion rate per BOE.

Other income (expense)

	Nine months ended September 30,						Increase			% Increase
	2007			2006			(Decrease)			(Decrease)
				(dollars in thousands)
Gain (loss) on derivatives not classified as hedges	$	(11,161	)	$	116		$	(11,277	)		(9,722	)%
Gain on ineffective portion of hedges		—			500			(500	)		(100	)%
Interest and other income		163			122			41			34	%
Interest expense, net		(13,449	)		(8,944	)		(4,505	)		50	%
Cost of debt retirement		(760	)		—			(760	)		N/A
Other expense		(91	)		(164	)		73			(45	)%
Equity in loss of pipelines and gathering system ventures		(663	)		(68	)		(595	)		875	%
Total	$	(25,961	)	$	(8,438	)	$	(17,523	)		208	%

Gain (loss) on derivatives not classified as hedges

     We recorded a loss of $11.1 million in 2007 for derivatives not classified as hedges, as compared to a gain of $116,000 for 2006. Future gains or losses on derivatives not classified as hedges will be impacted by the volatility of commodity prices and interest rates, as well as by the terms of any new derivative contracts.

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Interest expense

     Interest expense increased with the $92.0 million increase in the principal amount of our debt from approximately $147.0 million at September 30, 2006 to $239.0 million at September 30, 2007 along with an increase in our weighted average loan interest rate for 2007.

     Capitalized interest on work in progress decreased interest expense by $393,000 in 2007, a decrease of $153,000 compared to 2006.

Cost of debt retirement

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

Equity in loss of pipelines and gathering system venturers

     The loss associated with our equity investments increased $595,000 from $68,000 in 2006 to $663,000 in 2007. This change was primarily due to the Hagerman Gas Gathering System in New Mexico being operational for the entire nine months of 2007 versus a few months in 2006. During both 2006 and the 2007, production levels and related transportation volumes were not sufficient for profitable operation of this system. This resulted in an increase in our equity loss for this investment of $496,000. In addition, substantially all of the assets of West Fork Pipeline Company I and West Fork Pipeline Company V were sold in the fourth quarter of 2006. Without the operating results of these investments, our equity investment loss increased $139,000 for 2007.

Federal income tax

     Federal income tax expense was $2.0 million in 2007 compared to $7.8 million in 2006. Income tax expense for 2007 will be dependent on our earnings and is expected to be approximately 35% of income before income taxes.

Basic and diluted net income

     We had basic net income per share of $0.10 and $0.43 and diluted net income per share of $0.09and $0.42 for 2007 and 2006, respectively. Basic weighted average common shares outstanding increased from approximately 35.3 million shares in 2006 to approximately 37.8 million shares in 2007. The increase was primarily due to our public offering of 2.5 million shares of common stock in August 2006 and the exercise of employee and nonemployee stock options during 2007.

LIQUIDITY AND CAPITAL RESOURCES

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

     Working capital decreased approximately $15.1 million as of September 30, 2007 compared with December 31, 2006. Current liabilities exceeded current assets by $23.9 million at September 30, 2007. The working capital decrease was due to a decrease in cash and cash equivalents of approximately $592,000, and by a decrease in accounts receivable of approximately $3.4 million, an increase in accounts payable of approximately $6.4 million and an increase in current derivative obligations of $5.8 million.

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     We incurred net property costs of $111.5 million for the nine months ended September 30, 2007 compared to $155.1 million for the same period in 2006. The decrease is primarily related to the Harris acquisition in 2006. Our property expenditures were $110.0 million for the nine months of 2007. Included in our increased property basis for the nine months of 2007 and 2006 were net asset retirement costs of approximately ($505,000) and $2.0 million, respectively (see Note 8 to Consolidated Financial Statements). Historically, we have financed capital expenditures primarily with cash generated by operations, proceeds from bank borrowings and sales of our equity and debt 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.

     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.

     Stockholders’ equity at September 30, 2007 was $190.1 million, as compared to $183.8 million at December 31, 2006. The increase is primarily attributable to our net income of approximately $3.7 million and the exercise of employee options of approximately $2.4 million.

Credit Arrangements

     In the past, we have maintained two separate credit facilities. One of these credit facilities is our Third Amended and Restated Credit Agreement, as amended, or the “Revolving Credit Agreement”, with a group of bank lenders which, at September 30, 2007, provided us with a revolving line of credit having a “borrowing base” limitation of $150.0 million. The total amount that we can borrow and have outstanding at any one time is limited to the lesser of $350.0 million or the borrowing base established by the lenders. At September 30, 2007, the principal amount outstanding under our revolving credit facility was $89.0 million, excluding $445,000 reserved for our letters of credit. Our second credit facility was a five year term loan facility provided to us under a Second Lien Term Loan Agreement, or the “Second Lien Agreement”, with a group of banks and other lenders. The Second Lien Term Loan Agreement was paid off and terminated on July 31, 2007, with our payment to the lenders of $50.2 million, including interest. This payment was made with proceeds from our sale of unsecured senior notes, or “senior notes”.

     On July 31, 2007, we completed a private offering of unsecured senior notes in the principal amount of $150.0 million.

     As described below, in connection with our recent senior notes offering we entered into a Third Amendment to our Revolving Credit Agreement and paid off and terminated our Second Lien Agreement.

Revolving Credit Facility

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

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principal payments that may be required because of our outstanding loans being in excess of the borrowing base, interest only is payable monthly.

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

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

     The interest rate we are required to pay on our borrowings, including the applicable margin, may never be less than 5.00%. At September 30, 2007, our weighted average base and LIBOR rate, plus margin, was 7.64% on $89.0 million, the outstanding principal amount of our revolving loan on that date.

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

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

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

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

     The Revolving Credit Agreement contains various restrictive covenants, including (i) maintenance of a minimum current ratio, (ii) maintenance of a maximum ratio of funded indebtedness to earnings before interest, income taxes, depreciation, depletion and amortization, (iii) maintenance of a minimum net worth, (iv) prohibition of payment of dividends and (v) restrictions on incurrence of additional debt. We have pledged substantially all of our producing oil and natural gas properties to secure the repayment of our indebtedness under the Revolving Credit Agreement.

     As of September 30, 2007, we were in compliance with all of the covenants in our Revolving Credit Agreement.

     On July 31, 2007, we entered into a Third Amendment to the Revolving Credit Agreement upon completing our senior notes offering. This Third Amendment amended the Revolving Credit Agreement by, among other things:

• reducing the borrowing base from $190.0 million to $150.0 million;

• providing that our ratio of Consolidated Funded Debt to Consolidated EBITDA (as defined in the Revolving Credit Agreement) shall not exceed (i) 4.25 to 1.00 during the year 2007; (ii) 4.00 to 1.00 during the year 2008; or (iii) 3.50 to 1.00 during the year 2009 and thereafter, in

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each case calculated at the end of each fiscal quarter using the results of the twelve-month period immediately preceding the end of each such fiscal quarter;

• allowing for the issuance and sale of the senior notes;

• providing that an event of default under the senior notes will also constitute an event of default under the Revolving Credit Agreement.

Second Lien Term Loan Facility

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

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

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

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

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

Senior Notes

     On July 31, 2007, we completed a private offering of unsecured senior notes (the “senior notes”) in the principal amount of $150.0 million. The senior notes were recorded at the principal amount net of underwriters discount and related expenses of $4.8 million. The senior notes mature on August 1, 2014 and bear interest at 10.25 % which is payable semi-annually beginning on February 1, 2008. Considering the discount on the senior notes, the effective interest rate is 10.92%. Prior to August 1, 2010, we may redeem up to 35% of the senior notes for a price equal to 110.250% of the original principal amount of the senior notes with the proceeds of certain equity offerings. On or after August 1, 2011 we may redeem all or some of the senior notes at a redemption price that will decrease from 105.125% of the principal amount of the senior notes to 100% of the principal amount on August 1, 2013. In addition, prior to August 1, 2011, we may redeem some or all of the senior notes at a redemption price equal to 100% of the principal amount of the senior notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. Generally, the “make-whole” premium is an amount equal to the greater of (a) 1% of the principal amount of the senior notes being redeemed and (b) the excess of the present value of the redemption price of such notes as of August 1, 2011 plus all required interest payments due through August 1, 2011 (computed at a discount rate equal to a specified U.S. “Treasury Rate” plus 50 basis points), over the principal amount of the senior notes being redeemed. We have agreed to use our reasonable best efforts to exchange the senior notes for registered, freely tradable notes which otherwise have substantially identical terms to the senior notes within 210 days of July 31, 2007.

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     The indenture governing the senior notes restricts our ability to: (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the senior notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business.

     The net proceeds, after payment of typical transaction expenses, of the senior notes of approximately $143.5 million were used first to retire our Second Lien Term Loan with the remainder being applied to our Revolving Credit Facility.

Shelf Registration

     On October 17, 2007 we filed a registration statement on Form S-3 with the Securities and Exchange Commission. The universal shelf registration statement will allow us to issue common stock, preferred stock, warrants, senior debt and subordinated debt up to an aggregate amount of $250 million.

     Under the registration statement, we may periodically offer one or more of these securities in amounts, prices and on terms to be announced when and if the securities are offered. At the time any of the securities covered by the registration statement are offered for sale, a prospectus supplement will be prepared and filed with the Securities and Exchange Commission containing specific information about the terms of any such offering.

Interest Accrued

     Interest accrued for the nine months ended September 30, 2007, on our credit arrangements, was approximately $13.5 million. Of this amount, approximately $393,000 was capitalized.

Commodity Price Risk Management Transactions and Effects of Derivative Instruments

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

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

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

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

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     Certain of our commodity price risk management arrangements have required us to deliver cash collateral or other assurances of performance to the counterparties in the event that our payment obligations with respect to our commodity price risk management transactions exceed certain levels.

Contractual Obligations, Commitments and Off-Balance Sheet Arrangements

     We have contractual obligations and commitments that affect our financial position. Based on our assessment of the provisions and circumstances of our contractual obligations and commitments, we do not believe these obligations and commitments will materially adversely affect our consolidated results of operations, financial condition or liquidity.

     The following table is a summary of significant contractual obligations as of September 30, 2007:

	Obligation Due in Period
	Three months
	ending
	December 31,		Periods ending December 31,								After
Contractual Cash Obligations	2007		2008		2009		2010		2011		5 years		Total
	(in thousands)
Revolving Credit Facility (secured)(1)	$	1,714	$	6,818	$	6,800	$	94,663	$	—	$	—	$	109,995
Senior Notes (unsecured)(2)		—		15,418		15,375		15,375		15,375		196,125		257,668
Office Lease (Dinero Plaza)		51		210		216		36		—		—		513
Andrews and Snyder Field Offices(3)		5		14		14		14		14		598		659
Asset retirement obligations(4)		474		150		103		122		53		3,900		4,802
Derivative Obligations		5,520		18,813		780		225		—		—		25,338
Total	$	7,764	$	41,423	$	23,288	$	110,435	$	15,442	$	200,623	$	398,975

(1)	Outstanding principal of $89.0 million due October 31, 2010 and estimated interest obligation calculated using the weighted average rate at September 30, 2007 of 7.64%
(2)	Principal of $150.0 million due August 1, 2014 bearing interest at 10.25% which is payable semi-annually beginning February 1, 2008.
(3)	The Snyder office lease expires up on the cessation of production from the Diamond “M” area wells. The Andrews office lease would have expired in December 2007, however, Parallel exercised an option to purchase this office lease at the end of October 2007. The lease cost for these two office facilities are billed to nonaffiliated third party working interest owners under our joint agreements with these third parties.
(4)	Assets retirement obligations of oil and natural gas assets, excluding salvage value and accretion.

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

     We have no off-balance sheet arrangements.

Outlook

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

• internally generated cash from operations;

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• proceeds from bank borrowings; and

• proceeds from sales of equity securities.

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

• our proved reserves;

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

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

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

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

• increased bank borrowings;

• sales of Parallel’s securities;

• sales of non-core properties; or

• other forms of financing.

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

     Oil and Natural Gas Price Trends

     Changes in oil and natural gas prices significantly affect our revenues, financial condition, cash flows and borrowing capacity. Markets for oil and natural gas have historically been volatile and we expect this trend to continue. Prices for oil and natural gas typically fluctuate in response to relatively minor changes in supply and demand, market uncertainty, seasonal, political and other factors beyond our control. Although we are unable to accurately predict the prices we receive for our oil and natural gas, any significant or sustained declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital.

     Our capital expenditure budgets are highly dependent on future oil and natural gas prices.

     During 2006, the average realized sales price for our oil and natural gas was $48.73 (unhedged) per BOE. For the nine months ended September 30, 2007, our average realized price was $47.86 (unhedged) per BOE.

     Production Trends

     Like all other oil and gas exploration and production companies, we experience natural production declines. We recognize that oil and gas production from a given well naturally decreases over time

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and that a downward trend in our overall production could occur unless these natural declines are offset by additional production from drilling, workover or recompletions activity, or acquisitions of producing properties. If any production declines we experience are other than a temporary trend, and if we cannot economically replace our reserves, our results of operations may be materially adversely affected and our stock price may decline. Our future growth will depend upon our ability to continue to add oil and natural gas reserves in excess of production at a reasonable cost.

     While we have achieved increased production and revenue in our New Mexico Wolfcamp and Barnett Shale projects, as a result of our significant investments in these areas, production growth in our Barnett Shale investments has been restricted due to limited pipeline capacity. We expect the completion of additional pipeline capacity to significantly ease these pipeline capacity restraints beginning in the first half of 2008.

     In recent periods, we have concentrated our drilling and development efforts on our resource natural gas projects in the Barnett Shale and in New Mexico Wolfcamp. Due to limited development our oil production has decreased in accordance with normal decline curves for our principal Permian Basin and south Texas oil properties. We have increased our capital budget on the Harris San Andres field for 2007. We expect our 2008 capital budget to increase on our Permian Basin oil properties.

     Lease Operating Expense Trends

     The level of drilling, workover and maintenance activity in the primary areas in which we operate and produce continues at a historically high level. Service rates charged by oil field service companies have increased also significantly during recent periods. These increased cost levels have affected our per BOE lease operating expense. While we do not expect the rate of increase of service costs to continue at the same pace as in recent periods, further increases are possible and could significantly impact our per BOE lease operating expense.

     Interest Expense Trends

     As described above, on July 31, 2007 we completed a private offering of $150.0 million of senior notes that bear interest at 10.25%. As a result of the issuance of the notes and based on LIBOR interest rates applicable to our Second Lien Term Loan that was retired and the portion of our Revolving Credit Facility that was repaid with the net proceeds of the senior notes offering, we expect our annual interest expense will be increased by approximately $1.0 million. This incremental effect will increase if LIBOR rates decrease and decrease if LIBOR rates increase in subsequent periods.

Recent Accounting Pronouncements

     We adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109” (“FIN 48”), on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement 109, “Accounting for Income Taxes”, and prescribes a recognition threshold and measurement process for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

     Based on our evaluation, we have concluded that there are no significant uncertain tax positions requiring recognition in our financial statements. Our evaluation was performed for the tax years ended December 31, 2003, 2004, 2005 and 2006, the tax years which remain subject to examination by

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major tax jurisdictions as of September 30, 2007.

     We may from time to time be assessed interest or penalties by major tax jurisdictions, although any such assessments historically have been minimal and immaterial to our financial results.

     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“FAS 157”). FAS 157 defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosure requirements related to the use of fair value measures in financial statements. FAS 157 will be effective for our financial statements for the fiscal year beginning January 1, 2008; however, earlier application is encouraged. We are currently evaluating the timing of adoption and the impact that adoption might have on our financial position or results of operations.

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

Critical Accounting Policies

     Our critical accounting policies are included and discussed in our Annual Report on Form 10-K/A for the year ended December 31, 2006, as filed with the Securities and Exchange Commission on July 12, 2007. These critical accounting policies should be read in conjunction with the financial statements and the accompanying notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” also included in our Annual Report on Form 10-K/A for the year ended December 31, 2006.

FORWARD-LOOKING STATEMENTS

Cautionary Statement Regarding Forward-Looking Statements

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

• our future financial and operating performance and results;

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

• production volumes;

• availability of natural gas gathering and transmission facilities;

• our business strategy;

• market prices;

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

• development costs;

• number and location of planned wells;

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• 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,” “should”, “estimate,” “believe,” “continue,” “intend, “ “plan,” “budget,” “present value,” “future” or “reserves” or 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 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;

• dependent on key personnel;

• reliance on technological development and technology development programs;

• demand for oil and natural gas;

• losses due to future litigation;

• future capital requirements and availability of financing;

• geological concentration of our reserves;

• risks associated with drilling and operating wells;

• competition;

• general economic conditions;

• governmental regulations and liability for environmental matters;

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

• derivative decisions, including whether or not to hedge;

• terrorist attacks or war;

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

• fluctuations in interest rates and availability of capital.

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

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     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 under “Risks Related to Our Business” beginning on page 13 of our Form 10-K/A for the year ended December 31, 2006.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     The following quantitative and qualitative information is provided about market risks and derivative instruments to which we were a party at September 30, 2007, and from which we may incur future earnings, gains or losses from changes in market interest rates and oil and natural gas prices.

Interest Rate Sensitivity as of September 30, 2007

     Financial instruments sensitive to changes in interest rates are our senior notes, bank debt and interest rate swaps. The table below shows principal cash flows and related weighted average interest rates by expected maturity dates. Weighted average interest rates were determined using interest rates as of September 30, 2007. You should read Note 3 to the Consolidated Financial Statements for further discussion of our debt that is sensitive to interest rates.

													2011 and
	2007			2008			2009			2010			after			Total
	(in thousands, except interest rates)
Revolving Facility (secured)	$	—		$	—		$	—		$	89,000		$	—		$	89,000
Average interest rate		7.64	%		7.64	%		7.64	%		7.64	%		—
Senior notes	$	—		$	—		$	—		$	—		$	150,000		$	150,000
Average interest rate		10.25	%		10.25	%		10.25	%		10.25	%		10.25	%

     As the interest rate is variable and reflects current market conditions, the carrying value of our bank debt approximates the fair value.

     Interest on our senior notes and their carrying value are not affected by changes in interest rates. However, the fair value of the senior notes increases as interest rates decrease and their fair value decreases as interest rates increase. Because the Company has no present plan or intent to redeem the senior notes, changes in their fair value are not expected to have any effect on our cash flow in the foreseeable future.

     We employed fixed interest rate swap contracts with BNP Paribas and Citibank, N.A. based on the 90-day LIBOR rates at the time of the contract. These contracts are accounted for by “mark-to-market” accounting as prescribed in SFAS 133. As of September 30, 2007, the fair market value of these interest rate swaps was a liability of approximately $591,000.

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     A recap for the period of time, notional amounts, fixed interest rates, and fair market value of these contracts at September 30, 2007 follows:

						Estimated
	Notional		Fixed			Fair
Period of Time	Amounts		Interest Rates			Market Value
	($ in millions)					($ in thousands)
October 1, 2007 thru December 31, 2007	$	100		4.62	%	$	161
January 1, 2008 thru December 31, 2008	$	100		4.86	%		(323	)
January 1, 2009 thru December 31, 2009	$	50		5.06	%		(283	)
January 1, 2010 thru October 31, 2010	$	50		5.15	%		(146	)
Total Fair Market Value						$	(591	)

Commodity Price Sensitivity as of September 30, 2007

     Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce natural gas. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue. Oil prices ranged from a low of $51.65 per barrel to a high of $73.03 per barrel during 2006. Natural gas prices we received during 2006 ranged from a low of $1.00 per Mcf to a high of $15.11 per Mcf. During the period from January 1, 2007 to September 30, 2007, oil prices ranged from a low of $47.62 to a high of $77.69. Natural gas prices we received during this time ranged from a low of $1.37 per Mcf to a high of $12.69 per Mcf. A significant decline in the prices of oil or natural gas could have a material adverse effect on our financial condition and results of operations.

     We employ various derivative instruments in order to minimize our exposure to commodity price volatility. As of September 30, 2007, we had employed costless collars, collars, and swaps in order to protect against this price volatility. Although all of the contracts that we have entered into are viewed as protection against this price volatility, all contracts are accounted for by the “mark-to-market” accounting method as prescribed in SFAS 133.

     At September 30, 2007 we had oil collars and swaps in place covering future oil production of approximately 2.0 million barrels. Subsequent to September 30, 2007, oil futures prices have increased significantly and have risen to a level that would exceed a substantial portion of the “capped” price for each of our oil collars. If futures prices remain at this level, we will be required to remit the excess of the NYMEX price for each settlement period over the “cap” price contained in the respective collar contract as detailed in the table below. These increases in oil price will also require us to make larger net settlement payments under commodity swap contracts. While these payments should not significantly affect our cash flow since payments made to counterparties to these contracts should be substantially offset by increased commodity prices received on the sale of our production, the increase in oil prices, should they continue, will negatively affect the fair value of our commodities contracts as recorded in our balance sheet at December 31, 2007 and during future periods and, consequently, our reported net earnings. Changes in the recorded fair value of commodity derivatives are marked to market through earnings and are likely to result in substantial charges to earnings for the decrease in the fair value of these contracts during the fourth quarter of 2007. If oil prices continue to increase, this negative effect on earnings will become more significant. We are currently unable to estimate the effects on earnings in the fourth quarter of 2007, but the effects may be substantial.

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     A description of our active commodity derivative contracts as of September 30, 2007 follows:

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

     A summary of our collar positions at September 30, 2007 is as follows:

							Estimated
	Barrles of		NyMex Oil Prices				Fair Market
Period of Time	Oil		Floor		Cap		Value
							($ in thousands)
October 1, 2007 thru December 31, 2007		73,600	$	55.63	$	84.88	$	(108	)
January 1, 2008 thru December 31, 2008		237,900	$	60.38	$	81.08		(553	)
January 1, 2009 thru December 31, 2009		620,500	$	63.53	$	80.21		(473	)
January 1, 2010 thru October 31, 2010		486,400	$	63.44	$	78.26		(80	)

			Houston Ship
	M M Btu of		Channel Gas Prices
	Natural Gas		Floor		Cap
October 1, 2007 thru October 31, 2007		31,000	$	6.00	$	11.05	—

	M M Btu of		WAHA Gas Prices
	Natural Gas		Floor		Cap
October 1, 2007 thru October 31, 2007		93,000	$	6.25	$	8.90		75
October 1, 2007 thru March 31, 2008		1,098,000	$	6.50	$	9.50		472
Total Fair Market Value							$	(667	)

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

     We have entered into oil swap contracts with BNP Paribas. A summary of our commodity swap positions at September 30, 2007 is as follows:

					Estimated
	Number of		NyMex Oil		Fair Market
Period of Time	Barrels of Oil		Swap Price		Value
					($ in thousands)
October 1, 2007 thru December 31, 2007		119,600	$	34.36	$	(5,411	)
January 1, 2008 thru December 31, 2008		439,200	$	33.37		(17,923	)
Total fair market value					$	(23,334	)

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ITEM 4. CONTROLS AND PROCEDURES

     As of the end of the period covered by this Quarterly Report on Form 10-Q, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended) was evaluated by our management, with the participation of our Chief Executive Officer, Larry C. Oldham (principal executive officer), and our Chief Financial Officer, Steven D. Foster (principal financial officer), in accordance with rules of the Securities Exchange Act of 1934, as amended. Based on that evaluation, Mr. Oldham and Mr. Foster have concluded that our disclosure controls and procedures were effective as of September 30, 2007 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to management and recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

     There were no changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

     From time to time, we are party to ordinary routine litigation incidental to our business. We are not presently a defendant in any judicial proceedings, nor are we aware of any threatened litigation and we have not been a party to any bankruptcy, receivership, reorganization, adjustment or similar proceeding.

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

ITEM 1A. RISK FACTORS

     Except as set below, there have been no material changes from the risk factors as previously disclosed in our Form 10-K/A Report for the fiscal year ended December 31, 2006.

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Risks Relating to the Senior Notes and Our Other Indebtedness

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

     As of September 30, 2007, our total debt was $239.0 million (of which $150.0 million consisted of the senior notes due 2014 and $89.0 million consisted of borrowings under our revolving credit facility). Our level of debt could have important consequences for you, including the following:

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

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

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

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

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

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

     We may be able to incur substantially more debt in the future. Although the indenture governing the senior notes and the terms of our revolving credit facility contain restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. In addition, the indenture governing the senior notes and the terms of our revolving credit facility will not prevent us from incurring obligations that do not constitute indebtedness. To the extent new indebtedness is added to our current indebtedness levels, the risks described above could substantially intensify.

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

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

     If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. The indenture

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

     A default on our obligations could result in:

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

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

• our bankruptcy or liquidation, which is likely to result in delays in the payment of the senior notes or the revolving credit facility and in the exercise of enforcement remedies under the senior notes or our revolving credit facility.

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

     Restrictive debt covenants in the indenture and our revolving credit facility will restrict our business in many ways.

     The indenture governing the senior notes contains a number of significant covenants that, among other things, restrict our ability to:

• transfer or sell assets;

• make investments;

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

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

• create or incur liens;

• incur dividend or other payment restrictions affecting certain subsidiaries;

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

• enter into transactions with affiliates; and

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

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

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

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

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

     The senior notes are structurally subordinated to liabilities and indebtedness of our non-guarantor subsidiaries, if any, and are effectively subordinated to our secured indebtedness to the extent of the assets securing such indebtedness.

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

     In addition, the senior notes may not in the future be guaranteed by all of our subsidiaries, if any, and any non-guarantor subsidiaries can incur some indebtedness under the terms of the indenture. As a result, holders of the senior notes are structurally subordinated to claims of third party creditors of our

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non-guarantor subsidiaries. Claims of those other creditors, including trade creditors, holders of indebtedness, or guarantees issued by these non-guarantor subsidiaries will generally have priority as to the assets of the non-guarantor subsidiary over our claims and equity interests. As a result, holders of our indebtedness, including the holders of the senior notes, are structurally subordinated to all those claims.

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

     Federal and state statutes allow courts, under specific circumstances, to void subsidiary guarantees, or require that claims under the subsidiary guarantee be subordinated to all other debts of the subsidiary guarantor, and to require creditors such as the senior note holders to return payments received from subsidiary guarantors. Under federal bankruptcy law and comparable provisions of state fraudulent transfer laws, a subsidiary guarantee could be voided or claims in respect of a subsidiary guarantee could be subordinated to all other debts of that subsidiary guarantor if, for example, the subsidiary guarantor, at the time it issued its subsidiary guarantee:

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

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

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

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

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

     Generally, a subsidiary guarantor would be considered insolvent if:

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

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

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

     To the extent a court voids a subsidiary guarantee as a fraudulent transfer or holds the subsidiary guarantee unenforceable for any other reason, holders of senior notes would cease to have any direct claim against the subsidiary guarantor. If a court were to take this action, the subsidiary guarantor’s assets would be applied first to satisfy the subsidiary guarantor’s liabilities, if any, before any portion of its

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assets could be distributed to us to be applied to the payment of the senior notes. We cannot assure you that a subsidiary guarantor’s remaining assets would be sufficient to satisfy the claims of the holders of senior notes related to any voided portions of the subsidiary guarantees.

     We may not be able to repurchase the senior notes upon a change of control.

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

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

     In January 2003, we engaged Stonington Corporation for the purpose of obtaining general corporate financial advisory services and financial advisory services in the placement of our debt or equity securities. In December 2003, and under the terms of our agreement with Stonington, we issued to Stonington warrants to purchase an aggregate of 100,000 shares of our common stock as partial payment for services rendered for financial and investment advice provided by Stonington. The warrants were issued with an exercise price of $3.98 per share, the market value of our common stock at the date of issuance, and were exercisable during the four-year period commencing one year after the initial issuance of the warrants. The terms of the warrants provided for an expiration date of December 23, 2008 and granted certain rights of registration for the common stock issuable upon exercise of the warrants. The warrants contained customary antidilution provisions so as to avoid dilution of the equity interests represented by the underlying common stock upon the occurrence of certain events such as share dividends and splits. In the event of liquidation, dissolution or winding up of Parallel, holders of the warrants were not entitled to participate in the assets of Parallel. The warrants had no voting rights. The warrants were issued in a transaction not involving a public offering and were issued in reliance upon the exemption from registration under Section 4(2) of the Securities Act of 1933, as amended.

     The warrants could be exercised in whole or in part at any time during the period from December 23, 2004 to December 23, 2008 by payment in cash of an amount determined by multiplying the exercise price by the number of shares of common stock as to which the warrants are being exercised. The warrants also contained a “net exercise” provision entitling the holder to exercise the warrants by receiving shares of common stock equal to the value of the warrants being surrendered for exercise. Utilizing this net exercise feature, on July 11, 2007, warrants to purchase 50,000 shares of our common stock were surrendered for exercise and the holder received 41,221 shares of common stock. The other 50,000 shares were exercised in April 2007 as previously reported. No cash proceeds were received by Parallel. 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. We currently have no outstanding warrants.

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ITEM 6. EXHIBITS

(a)	Exhibits
	The following exhibits are filed herewith or incorporated by reference, as indicated:

No. Description of Exhibit

3.1	Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)
3.2	Bylaws of Registrant (Incorporated by reference to Exhibit No. 3.2 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
3.3	Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
3.4	Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.4 of the Registrant’s Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
3.5	Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.5 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
3.6	Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.1	Certificate of Designations, Preferences and Rights of Serial Preferred Stock — 6% Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)
4.2	Certificate of Designation, Preferences and Rights of Series A Preferred Stock (Incorporated by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000)
4.3	Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the Registrant filed with the Securities and Exchange Commission on October 10, 2000)
4.4	Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No. 4.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
4.5	Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
4.6	Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
4.7	Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American Stock Transfer, Inc. (Incorporated by reference to Exhibit No. 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

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No. Description of Exhibit

4.8	First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant, Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. (Incorporated by reference to Exhibit No. 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
4.9	Indenture dated as of July 31, 2007 between the Registrant and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.1 of the Registrant’s Form 8-K Report dated July 26, 2007)
4.10	Form of Rule 144A 101/4% Senior Notes due 2014 (Incorporated by reference to Exhibit 4.2 of the Registrant’s Form 8-K Report dated July 26, 2007)
4.11	Form of IAI Global Security 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.3 of the Registrant’s Form 8-K Report dated July 26, 2007)
4.12	Form of Regulation S 101/4% Senior Notes due 2014 (Incorporated by reference to Exhibit 4.4 of the Registrant’s Form 8-K Report dated July 26, 2007)
	Executive Compensation Plans and Arrangements (Exhibit No.’s 10.1 through 10.7):
10.1	1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
10.2	Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form 10-K for the fiscal year ended December 31, 1995)
10.3	Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005)
10.4	1998 Stock Option Plan (Incorporated by reference to Exhibit No. 10.4 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.5	2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form 10-Q Report for the fiscal quarter ended March 31, 2004)
10.6	2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated September 22, 2004)
10.7	Incentive and Retention Plan (Incorporated by reference to Exhibit No. 10.7 of the Registrant for the fiscal year ended December 31, 2006)
10.8	First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the Registrant, dated December 20, 2002)
10.9	Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December 20, 2002)
10.10	First Amendment to First Amended and Restated Credit Agreement, dated as of September 12, 2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003)

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No. Description of Exhibit

10.11	Second Amended and Restated Credit Agreement, dated September 27, 2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated September 27, 2004 and filed with the Securities and Exchange Commission on October 1, 2004)
10.12	Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
10.13	First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27, 2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated December 30, 2004 and filed with the Securities and Exchange Commission on December 30, 2004)
10.14	Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated April 4, 2005 and filed with the Securities and Exchange Commission on April 8, 2005)
10.15	Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated October 4, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.16	Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy, Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney, Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit 10.2 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.17	Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.18	Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.19	ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank, N.A. (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.20	Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas, CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrant’s Form 8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on December 30, 2005)

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No. Description of Exhibit

10.21	Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.4 of the Registrant’s Form 8-K Report, dated November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005)
10.22	Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas, N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C. (Incorporated by reference to Exhibit No. 10.5 of the Registrant’s Form 8-K Report, dated November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005)
10.23	Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.23 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.24	Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.24 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.25	Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated by reference to Exhibit No. 10.25 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.26	Purchase Agreement, dated July 26, 2007 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated July 26, 2007)
10.27	Registration Rights Agreement, dated July 31, 2007 (Incorporated by reference to Exhibit 10.2 of the Registrant’s Form 8-K Report dated July 26, 2007)
10.28	Third Amendment to Third Amended and Restated Credit Agreement dated as of July 31, 2007 between Parallel Petroleum Corporation individually and as successor by merger to Parallel L.P. and Parallel, L.L.C. and Citibank, N.A., successor by merger to Citibank Texas, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and Fortis Capital Corp. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 8-K Report dated July 26, 2007)
14	Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrant’s Form 10-K Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange Commission on March 22, 2004)
21	Subsidiaries (Incorporated by reference to Exhibit No. 21 of the Registrant’s Form 10-K Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange Commission on March 22, 2004)
*31.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
*31.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
*32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

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*32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

* Filed herewith.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PARALLEL PETROLEUM CORPORATION
	By: /s/ Larry C. Oldham
Date: November 9, 2007	Larry C. Oldham
	President and Chief Executive Officer
Date: November 9, 2007	By: /s/ Steven D. Foster
	Steven D. Foster,
	Chief Financial Officer

INDEX TO EXHIBITS

No. Description of Exhibit

3.1	Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)
3.2	Bylaws of Registrant (Incorporated by reference to Exhibit No. 3.2 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
3.3	Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
3.4	Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.4 of the Registrant’s Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
3.5	Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.5 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
3.6	Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
4.1	Certificate of Designations, Preferences and Rights of Serial Preferred Stock — 6% Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)
4.2	Certificate of Designation, Preferences and Rights of Series A Preferred Stock (Incorporated by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000)
4.3	Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the Registrant filed with the Securities and Exchange Commission on October 10, 2000)
4.4	Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No. 4.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)
4.5	Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
4.6	Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
4.7	Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American Stock Transfer, Inc. (Incorporated by reference to Exhibit No. 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
4.8	First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant, Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. (Incorporated by reference to Exhibit No. 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

No. Description of Exhibit

4.9	Indenture dated as of July 31, 2007 between the Registrant and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.1 of the Registrant’s Form 8-K Report dated July 26, 2007)
4.10	Form of Rule 144A 101/4% Senior Notes due 2014 (Incorporated by reference to Exhibit 4.2 of the Registrant’s Form 8-K Report dated July 26, 2007)
4.11	Form of IAI Global Security 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.3 of the Registrant’s Form 8-K Report dated July 26, 2007)
4.12	Form of Regulation S 101/4% Senior Notes due 2014 (Incorporated by reference to Exhibit 4.4 of the Registrant’s Form 8-K Report dated July 26, 2007)
	Executive Compensation Plans and Arrangements (Exhibit No.’s 10.1 through 10.7):
10.1	1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)
10.2	Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form 10-K for the fiscal year ended December 31, 1995)
10.3	Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005)
10.4	1998 Stock Option Plan (Incorporated by reference to Exhibit No. 10.4 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.5	2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form 10-Q Report for the fiscal quarter ended March 31, 2004)
10.6	2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated September 22, 2004)
10.7	Incentive and Retention Plan (Incorporated by reference to Exhibit No. 10.7 of the Registrant for the fiscal year ended December 31, 2006)
10.8	First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the Registrant, dated December 20, 2002)
10.9	Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December 20, 2002)
10.10	First Amendment to First Amended and Restated Credit Agreement, dated as of September 12, 2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003)
10.11	Second Amended and Restated Credit Agreement, dated September 27, 2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated September 27, 2004 and filed with the Securities and Exchange Commission on October 1, 2004)
10.12	Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

No. Description of Exhibit

10.13	First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27, 2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated December 30, 2004 and filed with the Securities and Exchange Commission on December 30, 2004)
10.14	Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated April 4, 2005 and filed with the Securities and Exchange Commission on April 8, 2005)
10.15	Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated October 4, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.16	Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy, Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney, Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit 10.2 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.17	Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.18	Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.19	ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank, N.A. (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form 8-K Report dated October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005)
10.20	Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas, CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrant’s Form 8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on December 30, 2005)
10.21	Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.4 of the Registrant’s Form 8-K Report, dated November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005)
10.22	Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas, N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C. (Incorporated by reference to Exhibit No. 10.5 of the Registrant’s Form 8-K Report, dated November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005)

No. Description of Exhibit

10.23	Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.23 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.24	Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.24 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.25	Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated by reference to Exhibit No. 10.25 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)
10.26	Purchase Agreement, dated July 26, 2007 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated July 26, 2007)
10.27	Registration Rights Agreement, dated July 31, 2007 (Incorporated by reference to Exhibit 10.2 of the Registrant’s Form 8-K Report dated July 26, 2007)
10.28	Third Amendment to Third Amended and Restated Credit Agreement dated as of July 31, 2007 between Parallel Petroleum Corporation individually and as successor by merger to Parallel L.P. and Parallel, L.L.C. and Citibank, N.A., successor by merger to Citibank Texas, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and Fortis Capital Corp. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 8-K Report dated July 26, 2007)
14	Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrant’s Form 10-K Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange Commission on March 22, 2004)
21	Subsidiaries (Incorporated by reference to Exhibit No. 21 of the Registrant’s Form 10-K Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange Commission on March 22, 2004)
*31.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
*31.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
*32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
*32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

* Filed herewith.