Edgar Filing: PARALLEL PETROLEUM CORP

e10vq

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, 2008 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.

Yes þ No o

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


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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY
PROCEEDINGS DURING THE PRECEDING FIVE YEARS:

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes o No o

As of October 30, 2008, the registrant had outstanding 41,597,161 shares of common stock.

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, 2008 (unaudited) and December 31, 2007		1

- Unaudited Consolidated Statements of Operations for the three months and nine months ended September 30, 2008 and 2007		3

- Consolidated Statements of Stockholders’ Equity for year ended December 31, 2007 and as of September 30, 2008 (unaudited)		4

- Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30, 2008 and 2007		5

- Notes to Consolidated Financial Statements		7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		22

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		43

ITEM 4. CONTROLS AND PROCEDURES		46

PART II. — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		46

ITEM 1A. RISK FACTORS		48

ITEM 6. EXHIBITS		51

SIGNATURES
EX-10.34
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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PART 1— FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PARALLEL PETROLEUM CORPORATION

Consolidated Balance Sheets
($ in thousands)


	September 30,			December 31,
	2008			2007
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	10,717		$	7,816

Accounts receivable:
Oil and natural gas sales		28,263			20,499
Joint interest owners and other, net of allowance for doubtful account of $50		2,736			2,460
Affiliates and joint ventures		5			3,970

		31,004			26,929
Other current assets		357			449
Derivatives		4,180			151
Deferred tax asset		5,894			10,293

Total current assets		52,152			45,638


Property and equipment, at cost:
Oil and natural gas properties, full cost method (including $128,464 and $86,402 not subject to depletion)		830,290			648,576
Other		3,317			2,877

		833,607			651,453
Less accumulated depreciation, depletion and amortization		(176,731	)		(145,482	)

Net property and equipment		656,876			505,971

Restricted cash		80			78
Investment in pipelines and gathering system ventures		332			8,638
Other assets, net of accumulated amortization of $1,469 and $1,193		4,204			2,768
Derivatives		5,013			—

	$	718,657		$	563,093

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

(1)

PARALLEL PETROLEUM CORPORATION
Consolidated Balance Sheets
($ in thousands)


	September 30,		December 31,
	2008		2007
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	58,868	$	47,848
Asset retirement obligations		780		598
Derivative obligations		21,506		30,424
Put premium obligations		464		—

Total current liabilities		81,618		78,870


Long-term liabilities :
Revolving credit facility		162,500		60,000
Senior notes (principal amount $150,000)		145,758		145,383
Asset retirement obligations		5,058		4,339
Derivative obligations		19,357		13,194
Put premium obligations		2,906		—
Deferred tax liability		36,323		26,045

Total long-term liabilities		371,902		248,961


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 41,597,161 and 41,252,644		415		412
Additional paid-in capital		199,597		196,457
Retained earnings		65,125		38,393

Total stockholders‘ equity		265,137		235,262

	$	718,657	$	563,093

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

(2)

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Operations

(unaudited)

(in thousands, except per share data)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Oil and natural gas revenues:
Oil and natural gas sales	$	56,201		$	29,487		$	156,217		$	79,957


Cost and expenses:
Lease operating expense		7,539			6,445			21,772			16,420
Production taxes		2,836			1,448			8,121			3,696
Production tax refund		—			—			—			(1,209	)
General and administrative		3,125			2,492			8,958			7,737
Depreciation, depletion and amortization		11,551			7,821			31,386			21,680


Total costs and expenses		25,051			18,206			70,237			48,324


Operating income		31,150			11,281			85,980			31,633


Other income (expense), net:
Gain (loss) on derivatives not classified as hedges		65,661			(4,556	)		(27,834	)		(11,161	)
Interest and other income		20			55			85			163
Interest expense		(6,139	)		(5,429	)		(17,025	)		(13,449	)
Cost of debt retirement		(102	)		(760	)		(102	)		(760	)
Other expense		(11	)		(76	)		(12	)		(91	)
Equity in gain (loss) of pipelines and gathering system ventures		(2	)		(69	)		380			(663	)

Total other income (expense), net		59,427			(10,835	)		(44,508	)		(25,961	)

Income before income taxes		90,577			446			41,472			5,672
Income tax expense, deferred		(31,900	)		(153	)		(14,740	)		(2,011	)

Net income	$	58,677		$	293		$	26,732		$	3,661


Net income per common share:
Basic	$	1.41		$	0.01		$	0.65		$	0.10

Diluted	$	1.41		$	0.01		$	0.64		$	0.09


Weighted average common shares outstanding:
Basic		41,566			38,033			41,429			37,791

Diluted		41,733			38,767			41,803			38,806

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

(3)

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Stockholders’ Equity
Year-Ended December 31, 2007 and as of September 30, 2008
(unaudited)
(in thousands)


	Common stock				Additional				Total
	Number of				paid-in		Retained		stockholders’
	shares		Amount		capital		earnings		equity
Balance
December 31, 2007		41,253	$	412	$	196,457	$	38,393	$	235,262
Common stock issued to directors		22		—		335		—		335
Warrants exercised, net of transaction costs		148		1		795		—		796
Options exercised		174		2		733		—		735
Stock offering costs		—		—		368		—		368
Stock option expense		—		—		772		—		772
Tax benefit of stock option exercise in excess of compensation		—		—		137		—		137
Net income		—		—		—		26,732		26,732

Balance
September 30, 2008		41,597	$	415	$	199,597	$	65,125	$	265,137

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

(4)

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2008 and 2007
(unaudited)
($ in thousands)


	2008			2007
Cash flows from operating activities:
Net income	$	26,732		$	3,661
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		31,386			21,680
Gain on sale of automobiles		—			(25	)
Accretion of asset retirement obligation		275			243
Accretion of senior notes discount		375			114
Deferred income tax expense		14,740			2,011
Loss on derivatives not classified as hedges		27,834			11,161
Amortization of deferred financing cost		509			372
Cost of debt retirement		102			760
Accretion of interest on put obligations		45			—
Common stock issued in lieu of cash for directors fees		335			96
Stock option expense		772			161
Equity in (gain) loss of pipelines and gathering system ventures		(380	)		663
Bad debt expense		—			(30	)
Changes in assets and liabilities:
Other assets, net		(1,409	)		(146	)
Restricted cash		(2	)		272
Accounts receivable		(4,001	)		3,438
Other current assets		92			713
Accounts payable and accrued liabilities		11,020			6,385

Net cash provided by operating activities		108,425			51,529


Cash flows from investing activities:
Additions to oil and natural gas properties		(172,381	)		(110,015	)
Proceeds from disposition of oil and natural gas properties and other property and equipment		—			1,711
Additions to other property and equipment		(577	)		(340	)
Settlements on derivative instruments		(36,306	)		(9,875	)
Net investment in pipelines and gathering system ventures		(21	)		(2,830	)

Net cash used in investing activities		(209,285	)		(121,349	)


Cash flows from financing activities:
Borrowings from bank line of credit		102,500			68,500
Payments on bank line of credit		—			(94,500	)
Payment on term loan		—			(50,000	)
Senior notes (principal amount $150,000)		—			145,186
Deferred financing cost		(270	)		(2,346	)
Proceeds from exercise of stock options and warrants		1,531			2,388

Net cash provided by financing activities		103,761			69,228


Net increase (decrease) in cash and cash equivalents		2,901			(592	)
Cash and cash equivalents at beginning of period		7,816			5,910


Cash and cash equivalents at end of period	$	10,717		$	5,318

(5)

PARALLEL PETROLEUM CORPORATION

Consolidated Statements of Cash Flows — Continued

Nine Months Ended September 30, 2008 and 2007
(unaudited)
($ in thousands)


Non-cash financing and investing activities:
Deferred purchase of derivative puts	$	3,325		$	—
Oil and natural gas properties asset retirement obligations	$	626		$	(505	)
Property transfer:
Transfer to oil and natural gas properties	$	8,707		$	—
Transfer from equity investment	$	(8,707	)	$	—
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	$	19,385		$	10,451

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

(6)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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

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

Parallel Petroleum Corporation, or “Parallel”, is engaged in the acquisition, development and exploitation of long-lived oil and natural gas reserves and, to a lesser extent, exploring for new oil and natural gas reserves. The majority of our producing properties are in the:

	•		Permian Basin of west Texas and New Mexico; and

	•		Fort Worth Basin of north Texas.

The financial information included herein is unaudited. The balance sheet as of December 31, 2007 has been derived from our audited Consolidated Financial Statements as of December 31, 2007. 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 2007 amounts have been conformed to the 2008 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 under certain rules and regulations of the Securities and Exchange Commission. The financial statements included in this report should be read in conjunction with the audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2007.

Unless otherwise indicated or unless the context otherwise requires, all references to “we”, “us”, “our”, “Parallel”, or “Company” mean the registrant, Parallel Petroleum Corporation and, where applicable, its former consolidated subsidiaries.

NOTE 2. STOCKHOLDERS’ EQUITY

Parallel accounts 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)).

Options

For the three months ended September 30, 2008 and 2007, we recognized compensation expense of approximately $545,000 and $101,000, respectively, with a tax benefit of approximately $185,000 and $34,000, respectively. For the nine months ended September 30, 2008 and 2007, Parallel recognized compensation expense of approximately $772,000 and $161,000, respectively, with a tax benefit of approximately $263,000 and $55,000, respectively, associated with our stock option grants.

During June 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 the director. 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

(7)

includes a cumulative adjustment for amounts previously expensed and associated with options estimated to be forfeited or surrendered.

The following table presents future stock-based compensation expense for our outstanding stock options which we expect to recognize during the indicated vesting periods:


	($ in thousands)
Fourth quarter 2008		549
2009		1,534
2010		789
2011 and 2012		480

Total	$	3,352

At September 30, 2008, options to purchase 293,000 shares of common stock were outstanding and vested. At that same date, options to purchase 446,000 shares were outstanding and unvested. During the nine months ended September 30, 2008, options to purchase 355,000 shares were granted to officers and employees, options to purchase 174,000 shares of common stock were exercised and no options expired or were forfeited.

The fair value of each option award is estimated on the date of grant. The fair value of stock options granted prior to and remaining outstanding at September 30, 2008 and that covered 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 implied volatilities from traded options and historical volatility of our stock. The expected term of the options granted used in the Black-Scholes model represent the period of time that options granted are expected to be outstanding. Risk free rates are based on the U.S. Treasury, Daily Treasury Yield Curve Rate.


	2008			2007			2005			2001
Expected volatility		46.50	%		52.52	%		54.20	%		57.95	%
Weighted-average volatility		46.50	%		52.52	%		54.20	%		57.95	%
Expected dividends		0.00			0.00			0.00			0.00
Expected term (in years)		6.25			5.75			6.50			7.50
Risk-free rate		3.81%-3.86	%		4.89	%		4.20	%		5.05	%

A summary of the stock option activity as of September 30, 2008 is presented below:


						Weighted
						Average
				Weighted		Remaining
				Average Exercise		Contractual		Aggregate
	Options			Price		Term		Intrinsic Value
	(in thousands)					(years)		($ in thousands)
Outstanding December 31, 2007		558		$	7.03
Granted		355		$	21.02
Exercised		(174	)	$	4.23
Surrendered		—		$	—

Outstanding September 30, 2008		739		$	14.41		9.0	$	1,095

Exercisable at September 30, 2008		293		$	7.30		4.9	$	995


	($ in thousands)
Average weighted grant date fair value of options issued and unvested, September 30, 2008	$	4,383
Average weighted grant date fair value of options issued and outstanding, September 30, 2008	$	5,617

(8)

We have outstanding stock options granted under six separate plans. 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.

For the nine months ended September 30, 2008 cash received from the exercise of stock options was approximately $735,000 with an estimated $137,000 tax benefit.

Restricted Stock

On June 12, 2008, 10,000 shares of restricted stock were awarded to a non-employee director under our 2008 Long-Term Incentive Plan. The fair value of the restricted stock award was based on the last sales price of our common stock on the Nasdaq Global Market on the date of grant. For the three and nine months ended September 30, 2008, we recognized compensation expense of approximately $24,000 and $81,000, respectively for restricted stock. These shares vest in four equal increments on June 12^th of each year, commencing on June 12, 2008.

The following table presents future stock-based compensation expense for the restricted stock award, which we expect to recognize during the indicated vesting periods:


	($ in thousands)
Fourth quarter 2008		24
2009		67
2010		29
2011		7

Total	$	127

A summary of restricted stock activity as of September 30, 2008 is presented below:


						Weighted
						Average
						Remaining
				Award Date		Contractual
	Restricted Stock			Fair Value		Term
						(years)
Outstanding December 31, 2007		—		$	—
Granted		10,000		$	20.91
Vested		(2,500	)	$	20.91
Surrendered		—		$	—

Non-vested shares at September 30, 2008		7,500		$	20.91		2.7

Stock Awards

For the three and nine months ended September 30, 2008, compensation expense related to stock awards totaled approximately $94,000 and $254,000, respectively.

On June 12, 2008, each of our four non-employee directors was awarded 1,912 shares of common stock under our 2008 Long-Term Incentive Plan. The fair value of the common stock awarded of $20.91 per share was based on the last sales price of our common stock on the Nasdaq Global Market on the date of grant. The shares vested 100% on the date of the grant.

On July 1, 2008, each of our four non-employee directors were awarded 1,153 shares of common stock under our 2004 Non-Employee Director Stock Grant Plan. The fair value of common stock awarded of $20.25 per share was based on the average of the high and low sales price of our common stock on the Nasdaq Global Market on the date of grant. The shares vested 100% on the date of the grant.

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Warrants

On April 15, 2008, our registration statement relating to 300,030 shares of common stock issuable upon the exercise of outstanding warrants was declared effective by the Securities and Exchange Commission. The warrants were issued in our initial public offering in 1980, as a component of units of common stock and warrants that were sold by us. Under terms of the warrants, holders of the warrants were entitled to purchase one share of common stock for each warrant exercised. The warrants were exercisable at $6.00 per share at any time on or before 5:00 p.m., Mountain Time, on May 15, 2008, at which time the warrants expired. Between April 15, 2008 and May 15, 2008 a total of 148,757 warrants were exercised for net proceeds of approximately $796,000.

NOTE 3. CREDIT FACILITIES

In the past, we have maintained two separate credit facilities. One of these credit facilities is our Fourth Amended and Restated Credit Agreement, dated May 16, 2008, or “Revolving Credit Agreement”, with a group of bank lenders that provide us with a revolving line of credit having a “borrowing base” limitation of $230.0 million at September 30, 2008. The total amount that we can borrow and have outstanding at any one time is limited to the lesser of $600.0 million or the borrowing base established by the lenders. At September 30, 2008, the principal amount outstanding under our revolving credit facility was $162.5 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 Agreement was paid in its entirety and terminated on July 31, 2007 with our payment to the lenders of $50.2 million, including interest.

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 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 revolving credit facility in an amount equal to the excess. Except for principal payments that may be required because of our outstanding loans being in excess of the borrowing base, interest only is payable monthly.

As of September 30, 2008, our group of bank lenders included Citibank, N.A., BNP Paribas, Compass Bank, Comerica Bank, Bank of Scotland plc, Texas Capital Bank, N.A. and Western National Bank.

Descriptions of the principal terms of the Revolving Credit Agreement, prior to its amendment on October 31, 2008, are set forth in the following paragraphs.

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 by it from time to time.

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 loan. 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

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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 4.75%. At September 30, 2008, our base rate, plus the applicable margin, was 5.0% on $162.5 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; provided that if the applicable interest period is longer than three months, interest is payable at three-month intervals following the first day of such 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 increase.

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.

All outstanding principal and accrued and unpaid interest under the revolving credit facility is due and payable on December 31, 2013. 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.

As of September 30, 2008 we were in compliance with our Revolving Credit Agreement.

As a result of recent conditions in the capital markets and all of the surrounding uncertainties, we concluded that it would be prudent to draw an additional $62.5 million under our line of credit in order to assure availability of and access to these funds. However, in view of the difficulties experienced by many banking institutions, it is possible that we could also become exposed to certain risks faced by our bank lenders, including legal, political, regulatory, operational and other risks. We depend on our ability to withdraw funds on short notice to meet our obligations. A lender’s insolvency or inability to continue participating in our syndicate of banks in the ordinary course of business could have a material adverse effect on our financial condition and results of operations. Our lender group at September 30, 2008 was made up of seven lenders, and no one lender held more than 24% of the facility at September 30, 2008.

For information about the amendment of the Revolving Credit Agreement on October 31, 2008, see Note 12 — Subsequent Events.

Senior Notes

On July 31, 2007, we completed a private offering of unsecured senior notes, or the “senior notes” in the principal amount of $150.0 million. At September 30, 2008, the carrying value of our senior notes was $145.8 million. The senior notes mature on August 1, 2014 and bear interest at 10.25%, per annum, which is payable semi-annually beginning on February 1, 2008. Prior to August 1, 2010, we may redeem up to 35% of the senior notes for a price equal to 110.250% of the original principal amount of the senior notes with the proceeds of certain equity offerings. On or after August 1, 2011 we may redeem all or some of the senior notes at a redemption price that will decrease from 105.125% of the principal amount of the senior notes to 100% of the principal amount on August 1, 2013. In addition, prior to August 1, 2011, we may redeem some or all of the senior notes at a redemption price equal to 100% of the principal amount of the senior notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. Generally,

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

The indenture governing the senior notes restricts 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.

As of September 30, 2008 we were in compliance with our Senior Notes Agreement.

Interest Accrued

For the nine months ended September 30, 2008, the aggregate interest accrued under our revolving credit facility and our senior notes was approximately $16.2 million. Bank fees and note discount amortization was approximately $986,000 and interest capitalized was approximately $67,000 for the nine months ended September 30, 2008.

NOTE 4. PROPERTY EXCHANGE AND ACQUISITIONS

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 are 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.

On June 26, 2008 we exercised a preferential right and purchased the interests owned by an unrelated third party, in our operated Diamond M properties in Scurry County, Texas, effective May 1, 2008. The purchase price, approximately $35.5 million, was financed with borrowings under our revolving credit facility.

The acquired interest consisted of two components, including an 89% working interest in the Base production and reserves and a 22.3% working interest in the production and reserves above the Base. As used in our original trade agreement with the unrelated third party, the Base production and reserves generally referred to and meant future production and reserves defined by an established base production decline curve as of December 19, 2001. Prior to this acquisition, we did not own an interest in the Base production and reserves but owned a 65.7% working interest in the production and reserves above the Base. This acquisition resulted in an increase in our current ownership in the Base production and reserves from zero to an approximate 89% working interest (77% net revenue interest), and an increase in the production and reserves above the Base from a 65.7% working interest to an 88% working interest (76% net revenue interest).

As described in Note 10 below, in June 2008 we acquired all of the assets of the Hagerman Gas Gathering System Joint Venture.

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

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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, is generally written off as an expense. Under rules and regulations of the Securities and Exchange Commission, the excess above the ceiling may not be 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.

At September 30, 2008, the net book value of our oil and gas properties, less related deferred income taxes, was below the calculated ceiling. As a result, we were not required to record a reduction of our oil and gas properties under the full cost method of accounting.

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, 2008 and 2007, overhead costs capitalized were approximately $1.3 million and $1.1 million, respectively.

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. In addition, our revolving credit facility requires us to maintain derivative financial instruments which limit our exposure to fluctuating commodity prices 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 hedges are “marked-to-market” at each period end and the increases or decreases in fair values recorded to earnings.

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

Adoption of SFAS No. 157

We adopted SFAS No. 157, “Fair Value Measurements”, effective January 1, 2008 for all financial assets and liabilities. SFAS No. 157 provides standards and disclosures for assets and liabilities that are measured and reported at fair value. In February 2008, the FASB issued FSP No. 157-2, which delayed the effective date of SFAS No. 157 by one year for nonfinancial assets and liabilities. Beginning January 1, 2009, we will apply SFAS 157 fair value requirements to nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a recurring basis. As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS No. 157 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:

	Level 1:		Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

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	Level 2:		Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps and interest rate swaps.

	Level 3:		Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Our valuation models are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments primarily include derivative instruments, such as commodity price collars and puts. Although we review our counterparty’s valuation and assess the reasonableness of our prices and valuation techniques, we do not have sufficient corroborating market evidence to support classifying these price collars and put assets and liabilities as Level 2.

As required by SFAS No. 157, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table summarizes the valuation of our derivative financial instruments by SFAS No. 157 pricing levels as of September 30, 2008 (in thousands):


	Quoted Prices in
	Active Markets
	for Identical		Other Observable			Unobservable			Fair Value at
	Assets (Level 1)		Inputs (Level 2)			Inputs (Level 3)			September 30, 2008
Interest Swaps	$	—	$	(2,397	)	$	—		$	(2,397	)
Oil Puts	$	—	$	—		$	5,867		$	5,867
Oil & Gas Collars	$	—	$	—		$	(27,787	)	$	(27,787	)
Oil Swaps	$	—	$	(7,353	)	$	—		$	(7,353	)

	$	—	$	(9,750	)	$	(21,920	)	$	(31,670	)

The determination of the fair values above incorporates various factors required under SFAS No. 157. These factors include not only the impact of our nonperformance risk but also the credit standing of the counterparties involved in our derivative contracts.

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The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as level 3 in the fair value hierarchy (in thousands):


	Three Months Ended					Nine Months Ended
	September 30, 2008					September 30, 2008
	Derivative			Derivative		Derivative			Derivative
	Collars			Puts		Collars			Puts
Beginning balance	$	(88,018	)	$	2,900	$	(15,852	)	$	—
Total gains (losses)		56,649			2,967		(20,840	)		2,542
Settlements		3,582			—		8,905			—
Purchases		—			—		—			3,325
Transfers in and/or out of level 3		—			—		—			—

Ending balance	$	(27,787	)	$	5,867	$	(27,787	)	$	5,867


Change in unrealized gains (losses) included in earnings relating to derivatives still held as of September 30, 2008 ⁽¹⁾	$	60,231		$	2,967	$	(11,935	)	$	2,542


⁽¹⁾		Gains and losses (realized and unrealized) included in earnings for the three months and nine months ended September 30, 2008 are reported in other income on the Consolidated Statement of Operations.

During periods of market disruption, including periods of volatile oil and gas prices, rapid credit contraction or illiquidity, it may be difficult to value certain of our derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were in active markets with observable data that become illiquid due to the current financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition.

Interest Rate Sensitivity

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 “marked-to-market” accounting as prescribed in SFAS 133. We view these contracts as protection against future interest rate volatility. As of September 30, 2008, the fair market value of these interest rate swaps was a liability of approximately $2.4 million.

The table below recaps the nature of these interest rate swaps and the fair market value of these contracts as of September 30, 2008.


			Weighted Average			Estimated
	Notional		Fixed			Fair
Period of Time	Amounts		Interest Rates			Market Value
	($ in millions)					($ in thousands)
October 1, 2008 thru December 31, 2008	$	100		4.86	%	$	(264	)
January 1, 2009 thru December 31, 2009	$	100		4.22	%		(1,084	)
January 1, 2010 thru December 31, 2010	$	100		4.71	%		(822	)
January 1, 2011 thru December 31, 2011	$	100		4.60	%		(227	)

Total Fair Market Value						$	(2,397	)

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Commodity Price Sensitivity

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

Put Options. Puts are an option to sell an asset. For any put transaction, the counterparty is required to make a payment to the Company if the reference floating price for any settlement period is less than the put or floor price for such contract.

In June 2008, we entered into multiple put contracts with BNP Paribas. In lieu of making premium payments for the puts at the time of entering into our put contracts, we deferred payment until the settlement dates of the contracts. Future premium payments will be netted against any payments that the counterparty may owe to us based on the floating price. Due to the deferral of the premium payments, we will pay a total amount of premiums of $3.713 million which is $388,000 greater than if the premiums had been paid at the time of entering into the contracts. The $388,000 difference is recorded as a discount to the put premium obligations and recognized as interest expense over the terms of the contracts using the interest method. Through September 30, 2008, we have accrued $45,000 to interest expense. Accordingly, the balance of the put premium obligations at September 30, 2008 including accrued interest is $3.370 million.

A summary of our put positions at September 30, 2008 is as follows:


					Estimated
	Barrels of				Fair Market
Period of Time	Oil		Floor		Value
					($ in thousands)
January 1, 2009 through December 31, 2009		109,500	$	100.00	$	1,470
January 1, 2010 through December 31, 2010		134,100	$	100.00		2,083
January 1, 2011 through December 31, 2011		146,000	$	100.00		2,314

Total Fair Market Value					$	5,867

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, 2008 is as follows:


							Estimated
	Barrels of		NyMex Oil Prices				Fair Market
Period of Time	Oil		Floor		Cap		Value
							($ in thousands)
October 1, 2008 thru December 31, 2008		87,400	$	63.42	$	83.86		(1,581	)
January 1, 2009 thru December 31, 2009		620,500	$	63.53	$	80.21		(15,664	)
January 1, 2010 thru October 31, 2010		486,400	$	63.44	$	78.26		(13,869	)


	MM Btu of		WAHA Gas Prices
	Natural Gas		Floor		Cap
October 1, 2008 through December 31, 2008		920,000	$	7.38	$	9.28		1,793
January 1, 2009 through December 31, 2009		3,285,000	$	7.06	$	9.93		1,534

Total Fair Market Value							$	(27,787	)

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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.

A recap for the period of time, number of barrels and swap prices are as follows:

Estimated

Number of

NyMex Oil

Fair Market

Period of Time

Barrels of Oil

Swap Price

Value

($ in thousands)

October 1, 2008 thru December 31, 2008

110,400

33.37

(7,353

)

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, 2008 and 2007:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(dollars in thousands, except per share data)
Basic EPS Computation:
Numerator-
Net income	$	58,677	$	293	$	26,732	$	3,661

Denominator-
Weighted average common shares outstanding		41,566		38,033		41,429		37,791

Basic EPS:
Net income per share	$	1.41	$	0.01	$	0.65	$	0.10

Diluted EPS Computation:
Numerator-
Net income	$	58,677	$	293	$	26,732	$	3,661

Denominator-
Weighted average common shares outstanding		41,566		38,033		41,429		37,791
Employee stock options		167		521		300		749
Warrants		—		213		74		266

Weighted average common shares for diluted earnings per share assuming conversion		41,733		38,767		41,803		38,806

Diluted EPS:
Net income per share	$	1.41	$	0.01	$	0.64	$	0.09

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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,
	2008			2007			2008			2007
	(in thousands)
Beginning asset retirement obligation	$	5,606		$	4,842		$	4,937		$	5,063

Additions related to new properties		211			85			917			151

Revisions in estimated cash flows		(58	)		(130	)		(267	)		(297	)

Deletions related to property disposals		(9	)		(74	)		(24	)		(358	)

Accretion expense		88			79			275			243


Ending asset retirement obligation	$	5,838		$	4,802		$	5,838		$	4,802

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, 2004, 2005, 2006 and 2007, the tax years which remain subject to examination by major tax jurisdictions as of September 30, 2008.

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 SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements. This statement does not require any new fair value measurements but may require some entities to change their measurement practices. We adopted SFAS No. 157 effective January 1, 2008 and the adoption did not have a significant effect on our financial position or operating results.

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 became 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. This statement, for us, became effective in the first quarter of 2008 and it did not have any effect on our financial position or operating results as we did not elect to apply the Fair Value Method.

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

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of our first fiscal year beginning after December 15, 2008, which will be our fiscal year 2009. Based upon our balance sheet, the statement would have no impact.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (SFAS 161). This statement is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS 161 applies to all derivative instruments within the scope of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), as well as related hedged items, bifurcated derivatives, and nonderivative instruments that are designated and qualify as hedging instruments. Entities with instruments subject to SFAS 161 must provide more robust qualitative disclosures and expanded quantitative disclosures. SFAS 161 is effective prospectively for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application permitted. We are currently evaluating the disclosure implications of this statement.

NOTE 10. INVESTMENT IN GAS GATHERING SYSTEMS

As of September 30, 2008 we had total equity investments of $332,000 in the West Fork Pipeline II, L.P. Our current investment percentage in this limited partnership is 23.25848%. For the three months ended September 30, 2008 we recorded a loss of approximately $(2,000), compared to no gain or loss in West Fork Pipeline II, for the three month period ended September 30, 2007. For the nine months ended September 30, 2008, we recorded a loss of approximately $(1,000) compared to a gain of $5,000 in the West Fork Pipeline II, for the nine month period ended September 30, 2007.

In June 2008, we acquired all of the assets of the Hagerman Gas Gathering System Joint Venture, or the “Joint Venture”, in connection with winding up and terminating the Joint Venture. The winding up of the Joint Venture commenced on June 19, 2008. At the time of the winding up of the Joint Venture, the investment was transferred into oil and natural gas properties and subsequent results have been included in our operating income and not as an equity gain (loss) item in our Consolidated Statement of Operations.

For the three months ended September 30, 2008, we recorded an equity loss of $(2,000), compared to a loss of $(69,000) in the West Fork Pipeline II and Hagerman Gas Gathering System Joint Venture for the three months ended September 30, 2007. For the nine months ended September 30, 2008, we recorded a gain of $380,000, compared to a loss of $(663,000) in the West Fork Pipeline II and Hagerman Gas Gathering System Joint Venture for the nine months ended September 30, 2007. The increase in income from period to period is the result of greater gas volumes flowing through the Hagerman Gas Gathering System Joint Venture in 2008, as compared to 2007.

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NOTE 11. COMMITMENTS AND CONTINGENCIES

From time to time, we are party to ordinary routine litigation incidental to our business.

On April 14, 2008, we were added as a defendant to a lawsuit filed in 2007, styled Brady Briscoe vs. Capstar Drilling, L.P. (“Capstar”), Cause No. 21,287, in the 259th District Court of Jones County, Texas. The plaintiff has alleged that he was injured as the result of an accident while he was working, as an employee of an unrelated third party, on a drilling rig operated by Capstar. Capstar was conducting drilling operations for us. The plaintiff has asserted general allegations of negligence as to Capstar and, specifically, a failure to properly equip its drilling rig, further alleging that we were in charge of the drilling rig and the operational details of the plaintiff’s work. The plaintiff has sued for an amount of actual damages of up to $15.0 million, together with pre-judgment interest, post-judgment interest and exemplary damages. Capstar recently settled with the plaintiff and Capstar has been dismissed from the lawsuit. If judgment is entered against us, we would be entitled to a credit for the amount that the plaintiff has already received from Capstar.

Even though we cannot predict the ultimate outcome of this matter, we believe we have meritorious defenses and intend to vigorously contest this lawsuit. We have not established a reserve with respect to the plaintiff’s claims.

On March 24, 2008, a lawsuit was filed in the 24^th District Court of Jackson County, Texas, against us and twenty-two other defendants in Cause No. 07-6-13069, styled “Tony Kubenka, Carolyn Kubenka, Dennis J. Kallus, David J. Kallus, Mary L. Kallus, Patricia Kallus, Nova Deleon, Janie Figuerova, and Larkin Thedford, Plaintiffs v. Tri-C Resources, Inc., Marie S. Adian, Laura E. Adian, Glenn A. Fiew, Lynn Kramer, Debra Boysen, Carol J. Gleason, Alana Sue Curlee, Connie W. Marthiljohni, Claire E. Adian, Zachary D. Adian, Donald R. Starkweather, Inc., D.A. Webernick, Danette Bundick, Johnny A. Webernick, Donna Gail Glover, Sherry Shulze, William H. Webernick, Jr., TAC Resources, Inc., New Century Exploration, Inc., Allegro Investments, Inc., Parallel Petroleum Corporation and Welper Interests, LP”.

The nine plaintiffs in this lawsuit have named us and the other working interest owners, including Tri-C Resources, Inc., the operator, as defendants. The plaintiffs in this lawsuit allege that they are royalty owners under oil and gas leases which are part of a pooled gas unit (the “unit”) located in Jackson County, Texas, and that the defendants, including us, are owners of the leasehold estate under the plaintiffs’ leases and others forming the unit. Plaintiffs also assert that one of the leases (other than plaintiffs’ leases) forming part of the unit has terminated and, as a result, the defendants have not properly computed the royalties due to plaintiffs from unit production and have failed to properly pay royalties due to them. Plaintiffs have sued for an unspecified amount of damages, including exemplary damages, under theories of breach of contract (including breach of express and implied covenants of their leases) and conversion, and seek an accounting, a declaratory judgment to declare the rights of the parties under the leases, and attorneys’ fees, interest and court costs.

If a judgment adverse to the defendants were entered, as a working interest owner in the leases comprising the unit, we believe our liability would be proportionate to the ownership of the other working interest owners in the leases. We have filed an answer denying any liability. Although an initial exchange of discovery has occurred, we cannot predict the ultimate outcome of this matter, we believe we have meritorious defenses and intend to vigorously contest this lawsuit. We have not established a reserve with respect to plaintiffs’ claims.

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interest charges. The decrease in proposed tax was the result of information supplied by us to the examiner as well as discussions of the applicable tax statutes and regulations. In December 2007, we filed a protest documenting our complete disagreement with the adjustments proposed on the final examination report and requested a conference with the appeals office of the Service. The examination office of the Service filed a response to our protest in February 2008 with the appeals office. On June 4, 2008, our representatives met with the Service’s Appeals Officer to review specific issues related to our calculation of net income from oil and gas and the associated treatment of certain deductions. During this meeting we were advised that a request to issue an “advisory opinion” had been submitted to the National Office of the Service. Pending issuance of this advisory opinion, we will submit an amendment to our initial protest in further support of our position. We intend to vigorously contest the adjustment proposed by the Service and believe that we will ultimately prevail in our position. We have not recorded a liability for tax, interest, or penalties related to this matter based on our analysis. If a liability for additional income tax should later be determined to be more likely than not, we anticipate the adjustment to increase the federal income tax liability would be offset by an increase to a deferred tax asset and would not result in a charge to earnings. Any interest or penalties resulting from a subsequent determination of increased tax liability would require a charge to earnings. We believe that the effects of this matter would not have a material effect on our results of operations for the fiscal quarter in which we actually incur or establish a reserve account for interest or penalties.

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

We are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject, nor have we been a party to any bankruptcy, receivership, reorganization, adjustment or similar proceeding.

Effective January 1, 2005, we established a 401(k) Plan and Trust for eligible employees. For the three months ended September 30, 2008 and September 30, 2007 we made contributions to the 401(k) Plan and Trust of approximately $79,000 and $67,000, respectively. For the nine months ended September 30, 2008 and September 30, 2007, we made contributions to the 401(k) Plan and Trust of approximately $231,000 and $201,000, respectively.

NOTE 12. SUBSEQUENT EVENTS

As of September 30, 2008 the principal amount outstanding under our revolving credit facility was $162.5 million. In response to recent market conditions and to strengthen our liquidity, we drew a total of $62.5 million under our Revolving Credit Agreement in four separate borrowings from October 10, 2008 through October 20, 2008, bringing our total principal amount outstanding to $225.0 million at October 20, 2008. The majority of the $62.5 million has been temporarily invested in a demand deposit money market account. Accordingly, $5.0 million is available under the revolving credit facility. Our accounts with Citibank, N.A. are insured at the basic FDIC deposit insurance coverage limits of $250,000. We believe the possibility of a loss of our accounts with Citibank, N.A. is minimal.

On October 31, 2008, we entered into a First Amendment to our Fourth Amended and Restated Credit Agreement. Generally, the amendment increases our annual interest rate by one-fourth of one percent (.25%). Loans made to us under our revolving credit facility bear interest at the base rate of Citibank, N.A. or the “LIBOR” rate, at our election. The base rate is generally equal to the sum of (a) Citibank’s “prime rate” as announced by it from time to time and (b) a specified Base Rate Margin, the amount of which depends upon the outstanding principal amount of our loans. 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 specified Libor Margin percentage, the amount of which depends upon the outstanding principal amount of our loans. In the First Amendment, the “Base Rate Margin” was amended from zero percent per annum to:

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	•		one-fourth of one percent (.25%) when the borrowing base usage is equal to or greater than 75%; and

	•		zero percent when the borrowing base usage is less than 75%.

	In addition, the “Libor Margin” was amended to mean:

	•		2.75% when the borrowing base usage is equal to or greater than 75%;

	•		2.50% per annum when the borrowing base usage is equal to greater than 50% but less than 75%; and

	•		2.25% per annum when the borrowing base usage is less than 50%.

The amendment also established our borrowing base at $230 million, which is the same as our previous borrowing base.

Our bank lenders at October 31, 2008 include Citibank, N.A., BNP Paribas, Compass Bank, Bank of Scotland plc, Bank of America, N.A., Texas Capital Bank, N.A., Western National Bank and West Texas National Bank. None of the bank lenders held more than 21% of the facility at October 31, 2008.

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 2007 Annual Report on Form 10-K, 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.

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

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

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

Conduct Exploratory Activities. Although we do not emphasize exploratory drilling, we will selectively undertake exploratory projects that have known geological and reservoir characteristics that 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 is 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 ventures or other similar arrangements 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 strategy, including the amounts we have budgeted for our activities.

Operating Performance

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

	•		seasonal demand;

	•		weather;

	•		hurricane conditions in the Gulf of Mexico;

	•		availability of pipeline transportation to end users;

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

	•		to a lesser extent, world oil prices.

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Additional factors influencing our overall operating performance include:

	•		production expenses;

	•		overhead requirements;

	•		costs of capital; and

	•		effects of derivative contracts.

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, 2008 (the “Current Quarter”), the sale price we received for our crude oil production averaged $115.19 per barrel, compared with $69.45 per barrel for the three months ended September 30, 2007 (the “Comparable Quarter”). The average sales price we received for natural gas for the Current Quarter was $8.54 per Mcf, compared with $5.81 per Mcf for the Comparable Quarter. For information regarding prices received, refer to the selected operating data table under “-Results of Operations” on page 25.

For the nine months ended September 30, 2008 (the “Current Period”), the sale price we received for our crude oil production averaged $109.52 per barrel, compared with $59.98 per barrel for the nine months ended September 30, 2007 (the “Comparable Period”). The average sales price we received for natural gas for the Current Period was $8.78 per Mcf, compared with $6.14 per Mcf for the Comparable Period. For information regarding prices received, refer to the selected operating data table under “-Results of Operations” on page 25.

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 the relationship between capitalized costs and 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.

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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, 2008 and September 30, 2007.


	Three Months Ended				Nine Months Ended
	9/30/2008		9/30/2007		9/30/2008		9/30/2007
			(in thousands, except per unit data)
Production Volumes:
Oil (Bbls)		274		254		758		797
Natural gas (Mcf)		2,886		2,043		8,338		5,243
BOE⁽¹⁾		755		595		2,148		1,671
BOE per day		8.2		6.5		7.8		6.1

Sales Prices:
Oil (per Bbl)	$	115.19	$	69.45	$	109.52	$	59.98
Natural gas (per Mcf)	$	8.54	$	5.81	$	8.78	$	6.14
BOE price	$	74.45	$	49.62	$	72.73	$	47.86

Operating Revenues:
Oil	$	31,552	$	17,619	$	83,043	$	47,786
Natural gas		24,649		11,868		73,174		32,171

	$	56,201	$	29,487	$	156,217	$	79,957


Operating Expenses:
Lease operating expense	$	7,539	$	6,445	$	21,772	$	16,420
Production taxes		2,836		1,448		8,121		3,696
Production tax refund		—		—		—		(1,209	)
General and administrative		3,125		2,492		8,958		7,737
Depreciation, depletion and amortization		11,551		7,821		31,386		21,680

	$	25,051	$	18,206	$	70,237	$	48,324


Operating income	$	31,150	$	11,281	$	85,980	$	31,633


⁽¹⁾		A BOE means one barrel of oil equivalent using the ratio of six Mcf of gas to one barrel of oil.

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RESULTS OF OPERATIONS

For the Three Months Ended September 30, 2008 and 2007:

Our oil and natural gas revenues and production product mix are displayed in the following table for the Current and Comparable Quarters.

Oil and Gas Revenues


	Revenues						Production
	2008			2007			2008			2007
Oil (Bbls)		56	%		60	%		36	%		43	%
Natural gas (Mcf)		44	%		40	%		64	%		57	%

Total		100	%		100	%		100	%		100	%

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


	Three Months Ended September 30,				Increase		% Increase
	2008		2007		(Decrease)		(Decrease)
			(in thousands except per unit data)
Production Volumes
Oil (Bbls)		274		254		20		8	%
Natural gas (Mcf)		2,886		2,043		843		41	%
BOE ⁽¹⁾		755		595		160		27	%
BOE/Day		8.2		6.5		1.7		26	%

Sales Price
Oil (per Bbl)	$	115.19	$	69.45	$	45.74		66	%
Natural gas (per Mcf)	$	8.54	$	5.81	$	2.73		47	%
BOE price	$	74.45	$	49.62	$	24.83		50	%

Operating Revenues
Oil	$	31,552	$	17,619	$	13,933		79	%
Natural gas		24,649		11,868		12,781		108	%

Total	$	56,201	$	29,487	$	26,714		91	%


⁽¹⁾		A BOE means one barrel of oil equivalent using the ratio of six Mcf of gas to one barrel of oil.

Oil revenues

Average wellhead realized crude oil prices increased $45.74 per Bbl, or 66%, to $115.19 per Bbl in the Current Quarter, over the Comparable Quarter. This price increase resulted in increased revenues by approximately $12.5 million for the Current Quarter, as compared to the Comparable Quarter. Oil production increased by approximately 20,000 Bbls due primarily to new wells and the additional interest acquired in the Diamond M area, where volumes increased approximately 37,000 Bbls in the Current Quarter. This increase was partially offset with natural declines in the Andrews and Fullerton areas. The increase in production resulted in increased revenues of approximately $1.4 million in the Current Quarter over the Comparable Quarter.

Natural gas revenues

Average realized wellhead natural gas prices increased $2.73 per Mcf, or 47%, to $8.54 per Mcf in the Current Quarter, over the Comparable Quarter. This price increase accounted for an increase in revenue of approximately $7.9 million. Natural gas production increased by approximately 843,000 Mcf primarily due to

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new wells in the New Mexico Wolfcamp, Barnett Shale and the additional interest acquired in the Diamond M Deep areas in the Current Quarter. In June 2008, we acquired additional interests in the Diamond M Deep which also added to our natural gas revenues. The increase in production was offset with natural declines in the south Texas, Andrews and other Permian areas. The overall increase in natural gas volumes increased revenue approximately $4.9 million for the Current Quarter.

Cost and Expenses


	Three months ended September 30,				Increase		% Increase
	2008		2007		(Decrease)		(Decrease)
			($ in thousands)
Lease operating expense	$	7,539	$	6,445	$	1,094		17	%
Production taxes		2,836		1,448		1,388		96	%
General and administrative		3,125		2,492		633		25	%
Depreciation, depletion and amortization		11,551		7,821		3,730		48	%

Total	$	25,051	$	18,206	$	6,845		38	%

Lease operating expense

Lease operating expense increased approximately $1.1 million or 17%, to $7.5 million during the Current Quarter compared to $6.4 million for the Comparable Quarter. The increase in expense was due to higher electricity, water injection and well repair costs associated with the increased production in the New Mexico Wolfcamp and Barnett Shale areas and the additional Diamond M interests acquired in June 2008. Overall costs and volumes increased from the additional interest acquired in the Diamond M area and from the new wells drilled in the New Mexico Wolfcamp and Barnett Shale areas. Lifting costs (excluding production taxes) per BOE decreased to $9.99 for the Current Quarter compared to $10.84 per BOE in the Comparable Quarter due to increased production. Ad valorem taxes increased in the Current Quarter by approximately $231,000 over the Comparable Quarter due to an overall increase in our producing property values.

Production taxes

Production taxes increased $1.4 million for the Current Quarter, as compared to the Comparable Quarter. Production taxes were 5.0% of revenue for the Current Quarter compared to 4.9% of revenue for the Comparable Quarter. The increase is related to higher natural gas production and higher tax rates in the New Mexico area. Production taxes in future periods will be a function of product mix, production volumes, product prices and tax rates.

General and administrative

General and administrative expenses increased 25%, or $633,000, for the Current Quarter, over the Comparable Quarter. This increase was primarily due to increased stock based compensation expense of approximately $466,000 and an increase in staffing and salary cost of approximately $188,000 over the Comparable Quarter. This increase over the Comparable Quarter was partially offset by lower franchise taxes, and fees associated with consulting and related services in the Current Quarter. On a BOE basis, general and administrative costs were $4.14 per BOE in the Current Quarter, as compared to $4.19 per BOE in the Comparable Quarter.

Depreciation, depletion and amortization

Depreciation depletion and amortization expense increased 48%, or $3.7 million, in the Current Quarter, over the Comparable Quarter. Total depreciation, depletion and amortization per BOE was $15.30 for the Current Quarter and $13.14 for the Comparable Quarter. This increase is primarily attributable to an overall increase in actual and anticipated drilling costs. Increased cost levels affect both the depletable amounts of capitalized costs in 2008 and the depletion attributable to amounts of estimated future

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development costs on proved undeveloped properties. Our drilling over the past year and our future drilling plans are focused on our natural gas resource projects which have higher associated per BOE drilling and development costs due to the nature of the wellbores. 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)


	Three months ended September 30,						Increase			% Increase
	2008			2007			(Decrease)			(Decrease)
				($ in thousands)
Gain (loss) on derivatives not classified as hedges	$	65,661		$	(4,556	)	$	70,217			(1,541	)%
Interest and other income		20			55			(35	)		(64	)%
Interest expense, net		(6,139	)		(5,429	)		(710	)		13	%
Cost of debt retirement		(102	)		(760	)		658			(87	)%
Other expense		(11	)		(76	)		65			(86	)%
Equity in loss of pipelines and gathering system ventures		(2	)		(69	)		67			(97	)%

Total	$	59,427		$	(10,835	)	$	70,262			(648	)%

Gain (loss) on derivatives not classified as hedges

We recorded a gain of $65.7 million in the Current Quarter for derivatives not classified as hedges, as compared to a loss of $(4.6) million for the Comparable Quarter. The greatest impact of the change in fair market valuation was within our crude oil contracts due to the significant decrease in oil prices throughout the Current Quarter. We settled in cash a net payment of $13.5 million in derivative contracts during the Current Quarter. See Note 6 to Consolidated Financial Statements.

Interest expense

Interest expense increased approximately $710,000. The Current Quarter resulted in a higher interest expense of approximately $664,000 primarily due to higher average outstanding debt balances over the Comparable Quarter. Capitalized interest for the Current Quarter was approximately $23,000 and $47,000 for the Comparable Quarter. Our weighted average interest rate decreased to 7.63% for the Current Quarter, from 9.27% for the Comparable Quarter.

In the Comparable Quarter we wrote off the unamortized bank fees of $(760,000) associated with the Second Lien Term Loan that was retired in July 2007.

Equity in loss of pipelines and gathering system ventures

For the Current Quarter, our equity investments recorded a loss of $(2,000), compared to a loss of $(69,000) for the Comparable Quarter. This increase in earnings of approximately $67,000 was primarily due to the equity investments in the Hagerman Gas Gathering System Joint Venture being operated at a loss in the Comparable Quarter.

In June 2008, we acquired all of the assets of the Hagerman Gas Gathering System Joint Venture. The results of operations of the Hagerman Gas Gathering System are now included in our operating income and not as an equity gain / loss item in our Consolidated Statement of Operations. See Note 10 to Consolidated Financial Statements.

Income taxes, deferred

Income tax expense was approximately $31.9 million in the Current Quarter, as compared to

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approximately $153,000 in the Comparable Quarter. Income tax expense for 2008 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 $1.41 and $0.01 for the Current Quarter and the Comparable Quarter, respectively. Basic weighted average common shares outstanding increased from 38.0 million shares in the Comparable Quarter to 41.6 million shares in the Current Quarter. Diluted weighted average common shares outstanding increased from 38.8 million shares in the Comparable Quarter to 41.7 million shares in the Current Quarter. The increase in common shares was primarily due to our public offering of 3.0 million shares of common stock in December 2007, the exercise of employee and nonemployee stock options in 2007 and 2008 and the exercise of warrants during 2008.

RESULTS OF OPERATIONS

For the Nine Months Ended September 30, 2008 and 2007:

Percentages of our revenues and production, by product mix, are shown in the following table for the Current Period and Comparable Period.

Oil and Gas Revenues


	Revenues						Production
	2008			2007			2008			2007
Oil (Bbls)		53	%		60	%		35	%		48	%
Natural gas (Mcf)		47	%		40	%		65	%		52	%

Total		100	%		100	%		100	%		100	%

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


	Nine Months Ended September 30,				Increase			% Increase
	2008		2007		(Decrease)			(Decrease)
			(in thousands except per unit data)
Production Volumes
Oil (Bbls)		758		797		(39	)		(5	)%
Natural gas (Mcf)		8,338		5,243		3,095			59	%
BOE ⁽¹⁾		2,148		1,671		477			29	%
BOE/Day		7.8		6.1		1.7			28	%

Sales Price
Oil (per Bbl)	$	109.52	$	59.98	$	49.54			83	%
Natural gas (per Mcf)	$	8.78	$	6.14	$	2.64			43	%
BOE price	$	72.73	$	47.86	$	24.87			52	%

Operating Revenues
Oil	$	83,043	$	47,786	$	35,257			74	%
Natural gas		73,174		32,171		41,003			127	%

Total	$	156,217	$	79,957	$	76,260			95	%


⁽¹⁾		A BOE means one barrel of oil equivalent using the ratio of six Mcf of gas to one barrel of oil.

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Oil revenues

Average wellhead realized crude oil prices increased $49.54 per Bbl, or 83%, to $109.52 per Bbl in the Current Period over the Comparable Period. This price increase caused an increase in revenue of approximately $37.6 million. Oil production decreased by approximately 39,000 Bbls this was primarily due from natural declines in the Fullerton, Andrews and other Permian and south Texas areas where volumes declined 17,000 Bbls, 35,000 Bbls, 6,000 Bbls and 8,000 Bbls, respectively. Production declines were partially offset with new wells and the additional interests acquired in the Diamond M area in June 2008, where volumes show an increase of approximately 31,000 Bbls. The decrease in production caused a decrease in revenues of approximately $(2.3) million for the Current Period.

Natural gas revenues

Average realized natural gas prices increased $2.64 per Mcf, or 43%, to $8.78 per Mcf in the Current Period, over the Comparable Period. The price increase caused an increase in revenue of approximately $22.0 million. Natural gas production increased 59% which was attributable to new wells in our New Mexico and Barnett Shale areas increasing production approximately 3.4 Bcf, partially offset by natural declines in our other producing areas. The increase in natural gas volumes increased revenues approximately $19.0 million in the Current Period.

Cost and Expenses


	Nine months ended September 30,					Increase		% Increase
	2008		2007			(Decrease)		(Decrease)
			($ in thousands)
Lease operating expense	$	21,772	$	16,420		$	5,352		33	%
Production taxes		8,121		3,696			4,425		120	%
Production tax refund		—		(1,209	)		1,209		N/A
General and administrative		8,958		7,737			1,221		16	%
Depreciation, depletion and amortization		31,386		21,680			9,706		45	%

Total	$	70,237	$	48,324		$	21,913		45	%

Lease operating expense

Lease operating costs increased approximately $5.4 million, or 33%, to $21.8 million during the Current Period, from $16.4 million in the Comparable Period. Lifting cost (excluding production taxes) increased to $10.14 per BOE for the Current Period, compared to $9.83 per BOE in the Comparable Period. The increase was due primarily to higher workover expenses from casing repairs in the Fullerton area and an increase in overall cost from new wells in the New Mexico Wolfcamp, Barnett Shale areas and the additional Diamond M interests acquired in June 2008. Ad valorem taxes increased in the Current Period by approximately $929,000 over the Comparable Period due to an overall increase in our producing property values.

Production taxes

Production tax increased $4.4 million, in the Current Period, over the Comparable Period primarily due to a $76.3 million increase in revenue. Production taxes were 5.2% of revenue for the Current Period compared to 4.6% of revenue for the Comparable Period. The increase is related to higher natural gas production and higher tax rates in the New Mexico area. Production taxes in future periods will be a function of product mix, production volumes, product prices and tax rates.

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 during the period from March 2005 through January 2007. These refunds were received by the operator of these wells after the operator’s

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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

Total general and administrative expenses increased 16%, or approximately $1.2 million, in the Current Period, over the Comparable Period. This increase was primarily due to increased stock based compensation expense of approximately $857,000, and an increase in staffing and salary cost of approximately $604,000 over the Comparable Period. General and administrative expenses capitalized to the full cost pool were $1.3 million in the Current Period compared to $1.1 million in the Comparable Period. On a BOE basis, general and administrative costs decreased to $4.17 per BOE in the Current Period from $4.63 per BOE in the Comparable Period.

Depreciation, depletion and amortization

Depreciation, depletion and amortization expense increased 45%, or $9.7 million, in the Current Period, over the Comparable Period. Total depreciation, depletion and amortization expense per BOE was $14.61 for the Current Period and $12.98 for the Comparable Period. This increase is primarily 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 2008 and the depletion attributable to amounts of estimated future development costs on proved undeveloped properties. Our drilling over the past year and our future drilling plans are focused on our natural gas resource projects which have higher associated per BOE drilling and development costs than our drilling projects in the Permian Basin of west Texas and onshore gulf coast of south Texas due to the use of horizontal drilling and multi-stage stimulation techniques. These factors, when combined with the increase in the absolute level of our capital expenditures during 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
	2008			2007			(Decrease)			(Decrease)
				($ in thousands)
Loss on derivatives not classified as hedges	$	(27,834	)	$	(11,161	)	$	(16,673	)		149	%
Interest and other income		85			163			(78	)		(48	)%
Interest expense, net		(17,025	)		(13,449	)		(3,576	)		27	%
Cost of debt retirement		(102	)		(760	)		658			(87	)%
Other expense		(12	)		(91	)		79			(87	)%
Equity in gain (loss) of pipelines and gathering system ventures		380			(663	)		1,043			(157	)%

Total	$	(44,508	)	$	(25,961	)	$	(18,547	)		71	%

Loss on derivatives not classified as hedges

We recorded a loss of $(27.8) million in the Current Period for derivatives not classified as hedges, as compared to a loss of $(11.2) million for the Comparable Period. The greatest impact was a result of lower fair market value for our settled tranches during the Current Period compared to the fair market value recorded at the beginning of the Current Period and an increase in crude oil prices during the Current Period for unsettled tranches. We also added new contracts during the Current Period that showed a gain to partially offset the loss. We settled in cash a net payment of $36.3 million in derivative contracts during the Current Period. See Note 6 to Consolidated Financial Statements.

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Interest expense

Interest expense increased approximately $3.6 million. The Current Period included higher interest expense of approximately $2.7 million primarily due to higher average outstanding debt balances over the Comparable Period. Capitalized interest for the Current Period was approximately $67,000 and $393,000 for the Comparable Period. Our weighted average interest rate decreased to 8.32% for the Current Period, from 8.79% for the Comparable Period.

In the Comparable Period we wrote-off the unamortized bank fees of $(760,000) associated with the Second Lien Term Loan that was retired in July 2007.

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

For the Current Period, our equity investments recorded a gain of $380,000. This gain compares to a loss of $(663,000) for the Comparable Period. This increase in earnings of approximately $1.0 million is the result of increased volumes flowing through the Hagerman Gas Gathering System Joint Venture during the first part of the Current Period.

In June 2008, we acquired all of the assets of the Hagerman Gas Gathering System. The results of operations of the Hagerman Gas Gathering System are now included in our operating income and not as an equity gain/loss item in our Consolidated Statement of Operations. See Note 10 to Consolidated Financial Statements.

Income taxes, deferred

Income tax expense was $14.7 million in the Current Period, compared to an expense of $2.0 million in the Comparable Period. Income tax expense for 2008 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 $0.65 and $0.10 and diluted net income per share of $0.64 and $0.09 for 2008 and 2007, respectively. Basic weighted average common shares outstanding increased from approximately 37.8 million shares in the Comparable Period to approximately 41.4 million shares in Current Period. Diluted weighted average common shares outstanding increased from approximately 38.8 million shares in the Comparable Period to approximately 41.8 million shares in the Current Period. The increase was primarily due to our public offering of 3.0 million shares of common stock in December 2007, the exercise of employee and nonemployee stock options in 2007 and 2008 and warrant exercises in 2008.

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 depend on many factors, including the prices we receive for oil and natural gas we produce.

Our working capital deficit decreased approximately $(3.8) million as of September 30, 2008, compared with December 31, 2007. Current liabilities exceeded current assets by approximately $29.5 million at September 30, 2008. The working capital deficit decrease was due to a decrease in current derivative obligations of approximately $(8.9) million, an increase in accounts receivable of approximately $4.1 million and an increase in derivative assets of approximately $4.0 million partially offset by an increase in accounts payable of approximately $11.0 million and a decrease in deferred tax assets of approximately $(4.4) million.

We incurred net property costs of approximately $173.0 million for the nine months ended September 30, 2008, compared to $111.5 million for the same period in 2007. The increase is primarily

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related to drilling activity in the Barnett Shale and in the New Mexico Wolfcamp areas, as well as acquisitions in our core properties. Included in our property basis for the nine months of 2008 and 2007 were net changes in asset retirement costs of approximately $626,000 and $(505,000), respectively. See Note 8 to Consolidated Financial Statements.

Our capital investment budget will be funded from our estimated operating cash flows and our bank borrowings. If our cash flows and bank borrowings are not sufficient to fund all of our estimated capital expenditures, we may fund any shortfall with proceeds from the sale of our debt or equity securities, reduce our capital budget or effect a combination of these alternatives. The amount and timing of our expenditures are subject to change based upon market conditions, results of expenditures, new opportunities and other factors. In response to recent market conditions, we have revised our 2008 capital expenditures downward from $171.6 million to $153.9 million.

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to undertake or complete future drilling projects. We may, from time to time, seek additional financing, either in the form of increased bank borrowings, sale of debt or equity securities or other forms of financing and there can be no assurance as to the availability of any additional financing upon terms acceptable to us. To strengthen our liquidity in the current market environment we drew an additional $62.5 million against the revolving credit facility during the month of October 2008. See Note 12 – Subsequent Events.

Stockholders’ equity at September 30, 2008 was $265.1 million, as compared to $235.3 million at December 31, 2007. The increase is primarily attributable to our net income of approximately $26.7 million.

Bank Borrowings

In the past, we have maintained two separate credit facilities. One of these credit facilities is our Fourth Amended and Restated Credit Agreement, dated May 16, 2008, or “Revolving Credit Agreement”, with a group of bank lenders which provide us with a revolving line of credit having a “borrowing base” limitation of $230.0 million at September 30, 2008. The total amount that we can borrow and have outstanding at any one time is limited to the lesser of $600.0 million or the borrowing base established by the lenders. At September 30, 2008, the principal amount outstanding under our revolving credit facility was $162.5 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 Agreement was paid off and terminated on July 31, 2007 with our payment to the lenders of $50.2 million, including interest.

Revolving Credit Facility

As of September 30, 2008, our group of bank lenders included Citibank, N.A., BNP Paribas, Compass Bank, Comerica Bank, Bank of Scotland plc, Texas Capital Bank, N.A. and Western National Bank.

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

As of September 30, 2008 we were in compliance with our Revolving Credit Agreement.

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	•		one-fourth of one percent (.25%) when the borrowing base usage is equal to or greater than 75%; and

	•		zero percent when the borrowing base usage is less than 75%.

	In addition, the “Libor Margin” was amended to mean:

	•		2.75% when the borrowing base usage is equal to or greater than 75%;

	•		2.50% per annum when the borrowing base usage is equal to greater than 50% but less than 75%; and

	•		2.25% per annum when the borrowing base usage is less than 50%.

The amendment also established our borrowing base at $230 million, which is the same as our previous borrowing base.

Senior Notes

On July 31, 2007, we completed a private offering of unsecured senior notes, or the “senior notes”, in the principal amount of $150.0 million. At September 30, 2008, the carrying value of our senior notes was $145.8 million. The senior notes mature on August 1, 2014 and bear interest at 10.25%, per annum, which is payable semi-annually beginning on February 1, 2008. Prior to August 1, 2010, we may redeem up to 35% of the senior notes for a price equal to 110.250% of the original principal amount of the senior notes with the proceeds of certain equity offerings. On or after August 1, 2011 we may redeem all or some of the senior notes at a redemption price that will decrease from 105.125% of the principal amount of the senior notes to 100% of the principal amount on August 1, 2013. In addition, prior to August 1, 2011, we may redeem some or all of the senior notes at a redemption price equal to 100% of the principal amount of the senior notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. 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.

As of September 30, 2008 we were in compliance with our Senior Notes Agreement.

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Interest Accrued

For the Current Period, the aggregate interest accrued under our Revolving Credit Agreement and our senior notes was approximately $16.2 million. Bank fees and note discount amortization was approximately $986,000 for the Current Period and interest capitalized was approximately $67,000.

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.

At September 30, 2008 we had no derivatives in place that were designated as cash flow hedges. All commodity derivative contracts at September 30, 2008 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 2008 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 2008 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.

We adopted SFAS No. 157 “Fair Value Measurement” effective January 1, 2008 to measure fair value of our derivatives which had no significant effect on our financial position or operating results.

Management of risk requires, among other things, policies and procedures to record properly and verify a number of transactions and events. We have devoted resources to develop our risk management policies and procedures and expect to continue to do so in the future. Nonetheless, our policies and procedures may not be comprehensive. Many of our methods for managing risk and exposures are based upon the use of observed historical market behavior or statistics based on historical models. As a result, these methods may not fully predict future exposures, which can be significantly greater than our historical measures indicate. Other risk management methods depend upon the evaluation of information regarding markets, or other matters that is publicly available or otherwise accessible to us. This information may not always be accurate, complete, up-to-date or properly evaluated and our risk management policies and procedures may leave us exposed to unidentified or unanticipated risk, which could negatively affect our business. See “Quantitative and Qualitative Disclosures About Market Risk” under Item 3 in this Form 10-Q and in our 2007 Form 10-K.

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Contractual Obligations, Commitments and Off-Balance Sheet Arrangements

We have contractual obligations and commitments that may affect our financial position. However, based on our assessment of the provisions and circumstances of our contractual obligations and commitments, we do not believe there will be an adverse effect on our consolidated results of operations, financial condition or liquidity.

The following table is a summary of significant contractual obligations as of September 30, 2008:


	Obligation Due in Period
	Three months
	ending
	December 31,		Years ending December 31,								After
Contractual Cash Obligations	2008		2009		2010		2011		2012		5 years		Total
					(in thousands)
Revolving Credit Facility (secured)⁽¹⁾	$	2,042	$	8,125	$	8,125	$	8,125	$	8,147	$	170,625	$	205,189
Senior Notes (unsecured)⁽²⁾		—		15,375		15,375		15,375		15,375		180,750		242,250
Office Lease (Dinero Plaza)		67		271		107		31		—		—		476
Asset retirement obligations⁽³⁾		662		223		44		91		33		4,785		5,838
Derivative Obligations		9,198		16,748		14,691		226		—		—		40,863
Put premium obligations⁽⁴⁾		—		646		1,378		1,689		—		—		3,713

Total	$	11,969	$	41,388	$	39,720	$	25,537	$	23,555	$	356,160	$	498,329


(1)		Outstanding principal of $162.5 million due December 31, 2013 and estimated interest obligation calculated using the interest rate at September 30, 2008 of 5.0%. See Note 12 — Subsequent Events.

(2)		Outstanding principal of $150.0 million due August 1, 2014 and interest obligation calculated at an interest rate of 10.25%.

(3)		Assets retirement obligations of oil and natural gas assets, excluding salvage value and accretion.

(4)		The put premium obligations above rep resent the undiscounted obligation to our counterparty. We have recognized $45,000 of interest for the nine months ended September 30, 2008 and will recognize $343,000 interest associated with the put premium obligations over the remaining life of the contracts.

At September 30, 2008, we had no off-balance sheet debt or other off-balance sheet arrangements.

Trends and Outlook

Our business is influenced by trends that affect the oil and gas industry. In particular, recent declines in oil and natural gas prices and recent economic trends could adversely affect our business, liquidity, results of operations and financial conditions.

Our business is increasingly subject to the adverse trends that have taken place in the global capital markets recently. The recent events in the credit and stock markets indicate a high likelihood of a continuation of, and probable further expansion of, the economic weakness in the U.S. economy that began over one year ago. The spillover of deepening fears about our banking system may adversely impact investor confidence in us, our banking relationships, and the liquidity and financial condition of third parties with whom we conduct operations.

We expect to face the continuing challenges of weakness in the U.S. real estate market and increased mortgage delinquencies, investor anxiety over the U.S. economy, rating agency downgrades of various financial issuers, unresolved issues with structured investment vehicles, deleveraging of financial institutions and hedge funds and dislocation in the inter-bank market. If significant, continued volatility, changes in interest rates, defaults, market liquidity, declines in equity prices, and the strengthening or

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weakening of foreign currencies against the U.S. dollar, individually or in tandem, could have a material adverse effect on our liquidity, results of operations, financial condition or cash flows through realized losses, and impairments.

In response to current market conditions, we have:

•

revised our 2008 capital expenditures downward from $171.6 million to $153.9 million, of which:

	•		$14.2 million is associated with a 9 gross (9.0 net) well decrease in our previously planned drilling activity in the New Mexico Wolfcamp project;

	•		$2.3 million is associated with the deferral of 3 gross (2.6 net) wells in the Diamond M Canyon Reef project due to the unavailability of a drilling rig until November 15, 2008; and

	•		$1.2 million is associated with the deferral of 3 gross (2.9 net) wells in the Utah/Colorado project due to delays in permitting;

	•		adopted a less aggressive capital expenditure budget of $118.8 million for 2009;

	•		drawn an additional $62.5 million under our Revolving Credit Agreement and invested the majority of the $62.5 million in a demand deposit money market account for the purpose of strengthening our liquidity; and

	•		requested that our bank lenders not increase our borrowing base at the present time because of the associated interest rate and fee increases that our lenders advised us would accompany any such borrowing base increase.

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

	•		internally generated cash from operations;

	•		proceeds from bank borrowings; and

	•		proceeds from sales of equity and debt 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;

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

	•		events occurring within the global capital markets.

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;

	•		additional sales of our debt or equity securities;

	•		sales of non-core properties;

	•		other forms of financing; or

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•

a combination of the above.

Except for the revolving credit facility we have with our bank lenders, we do not currently have any agreements for any future financing and there can be no assurance as to the availability or terms of any such future 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. See Note 12 – Subsequent Events.

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

For the nine months ended September 30, 2007, the average realized sales price for our oil and natural gas was $47.86 per BOE. For the nine months ended September 30, 2008, our average realized price was $72.73 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 and that a downward trend in our overall production could occur unless these natural declines are offset by additional production from drilling, workover or recompletion 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.

In recent periods, we have concentrated our drilling and development efforts on our resource natural gas projects in our Barnett Shale and New Mexico Wolfcamp projects. Due to limited development, our production has decreased in accordance with normal decline curves for our principal Permian Basin oil properties and south Texas gas 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 significantly during recent periods and electrical cost has also increased. 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 lease operating expense.

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Interest Expense Trends

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 the increase in our current borrowings, we expect a corresponding increase in our annual interest expense. An increase in interest rates will also negatively impact our interest expense.

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.

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 December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated

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Financial Statements—an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008, which will be our fiscal year 2009. Based upon our balance sheet, the statement would have no impact.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (SFAS 161). This statement is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS 161 applies to all derivative instruments within the scope of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), as well as related hedged items, bifurcated derivatives, and nonderivative instruments that are designated and qualify as hedging instruments. Entities with instruments subject to SFAS 161 must provide more robust qualitative disclosures and expanded quantitative disclosures. SFAS 161 is effective prospectively for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application permitted. We are currently evaluating the disclosure implications of this statement.

Critical Accounting Policies

Our critical accounting policies are included and discussed in our Annual Report on Form 10-K for the year ended December 31, 2007, as filed with the Securities and Exchange Commission on February 20, 2008. 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” included in our Annual Report on Form 10-K for the year ended December 31, 2007.

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;

	•		our business strategy;

	•		market prices;

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

	•		development costs;

	•		number and location of planned wells;

	•		our future commodity price risk management activities; and

	•		our plans and forecasts.

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

We use the words “may,” “will,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “budget,” “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:

	•		difficult and adverse conditions in the global and domestic capital and credit markets;

	•		continued volatility and further deterioration of the capital and credit markets;

	•		uncertainty about the effectiveness of the U.S. government’s plan to purchase large amounts of illiquid, mortgage-backed and other securities from financial institutions;

	•		the impairment of financial institutions;

	•		exposure to financial and capital market risk;

	•		changes in general economic conditions, including the performance of financial markets and interest rates, which may affect our ability to raise capital and generate operating cash flow;

	•		unanticipated changes in industry trends;

	•		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 potential or future litigation;

	•		future capital requirements and availability of financing;

	•		geological concentration of our reserves;

	•		risks associated with drilling and operating wells;

	•		competition;

	•		general economic conditions;

	•		governmental regulations and liability for environmental matters;

	•		receipt of amounts owed to us by purchasers of our production and counterparties to our hedging contracts;

	•		hedging decisions, including whether or not to hedge;

	•		events similar to 911;

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

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•

fluctuations in interest rates and availability of capital.

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

Before you invest in our common stock, you should be aware that there are various risks associated with an investment. We have described some of these risks under Item 1A. Risk Factors on page 48 of this Quarterly Report and under “Risks Related to Our Business” beginning on page 13 of our Form 10-K for the year ended December 31, 2007.

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, 2008, 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, 2008

Although we are currently protected from interest rate volatility up to $250.0 million through our senior notes and our interest rate swaps, we are exposed to interest rate volatility on lending above this level. Our only financial instruments sensitive to changes in interest rates are our bank debt and interest rate swaps. As the interest rate is variable and reflects current market conditions, the carrying value of our bank debt approximates the fair value. The table below shows principal cash flows and related interest rates by expected maturity dates. Refer to Note 3 of the Consolidated Financial Statements for further discussion of our debt that is sensitive to interest rates.


													2012 and
	2008			2009			2010			2011			after			Total
				($ in thousands, except interest rates)
Revolving Credit Facility (secured)	$	—		$	—		$	—		$	—		$	162,500		$	162,500
Average interest rate		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%
Senior notes	$	—		$	—		$	—		$	—		$	150,000		$	150,000
Average interest rate		10.25	%		10.25	%		10.25	%		10.25	%		10.25	%

At September 30, 2008, we had outstanding bank loans in the aggregate principal amount of $162.5 million at a base interest rate of 5.0%, including applicable margin. Under our revolving credit facility, we may elect an interest rate based upon the agent bank’s base lending rate or the LIBOR rate, plus a margin ranging from 2.00% to 2.50% per annum, depending upon the outstanding principal amount of the loans. The interest rate we are required to pay, including the applicable margin, may never be less than 4.75%. A change in the interest rate of one percent could cause an approximate $600,000 change in interest expense on an annual basis on the current amount of borrowings, when factoring in the interest rate protection we have with our interest rate swaps.

At September 30, 2008, we had outstanding senior notes in the aggregate principal amount of $150.0 million bearing interest at a rate of 10.25% per annum. The carrying value of our 10.25% senior notes at September 30, 2008 was approximately $145.8 million. Interest on our senior notes and their carrying value are not affected by changes in interest rates.

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 contract. These contracts are accounted for by “mark-to-market” accounting as prescribed in SFAS 133. As of September 30, 2008, the fair market value of these interest rate swaps was a liability of approximately $2.4 million.

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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, 2008 follows:


			Weighted Average			Estimated
	Notional		Fixed			Fair
Period of Time	Amounts		Interest Rates			Market Value
	($ in millions)					($ in thousands)
October 1, 2008 thru December 31, 2008	$	100		4.86	%	$	(264	)
January 1, 2009 thru December 31, 2009	$	100		4.22	%		(1,084	)
January 1, 2010 thru December 31, 2010	$	100		4.71	%		(822	)
January 1, 2011 thru December 31, 2011	$	100		4.60	%		(227	)

Total Fair Market Value						$	(2,397	)

Commodity Price Sensitivity

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. NYMEX closing oil prices ranged from a low of $56.59 per barrel to a high of $83.32 per barrel during the nine months ended September 30, 2007. NYMEX closing natural gas prices during the nine months ended September 30, 2007 ranged from a low of $5.38 per Mcf to a high of $8.19 per Mcf. During the nine months ended September 30, 2008 NYMEX closing oil prices ranged from a low of $87.14 to a high of $145.29. NYMEX closing natural gas prices during the nine months ended September 30, 2008 ranged from a low of $7.22 per Mcf to a high of $13.58 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 the aforementioned commodity price volatility. As of September 30, 2008, we had employed costless collars, puts 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, 2008 we had crude oil collar, put and swap derivative contracts in place covering future oil production of approximately 1.7 million barrels. Crude oil futures prices have continued to decrease since September 30, 2008. If prices stay at current levels, the settlement price will be within the price range of the collar contracts, thus allowing for no cash payment at settlement date for either the company or our counterparties. In addition at current price levels, the settlement price will cause our counterparty to pay us at settlement date for our put contracts. However, we will continue to make payment at settlement date for our swap contracts. The swap contracts are set to expire at December 31, 2008.

At September 30, 2008 we had natural gas collar derivative contracts in place covering future natural gas production of approximately 4.2 Bcf. Natural gas futures prices have continued to decrease since September 30, 2008 and if prices stay at current levels, the company anticipates that we will either make no cash payment or we will receive payment from our counterparties for these natural gas derivative contracts at settlement date.

Changes in commodity prices will affect the fair value of our derivative contracts as recorded on our balance sheet during future periods and, consequently, our reported net earnings. The changes in the recorded fair value of the commodity derivatives are marked to market through earnings. If commodity prices decrease, this commodity price change will have a positive impact to our earnings. Conversely, if

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commodity prices increase, this commodity price change will have a negative effect on earnings. Each derivative contract is evaluated separately to determine its own fair value. Due to the current volatility of both crude oil and natural gas prices, we are currently unable to estimate the effects on earnings in future periods, but based on the volume of our future oil and gas production covered by commodity derivative contracts, the effects may be material.

Descriptions of our active commodity derivative contracts as of September 30, 2008 are set forth below:

A summary of our put positions at September 30, 2008 is as follows:


					Estimated
	Barrels of				Fair Market
Period of Time	Oil		Floor		Value
					($ in thousands)
January 1, 2009 through December 31, 2009		109,500	$	100.00	$	1,470
January 1, 2010 through December 31, 2010		134,100	$	100.00		2,083
January 1, 2011 through December 31, 2011		146,000	$	100.00		2,314

Total Fair Market Value					$	5,867

A summary of our collar positions at September 30, 2008 is as follows:


							Estimated
	Barrels of		NyMex Oil Prices				Fair Market
Period of Time	Oil		Floor		Cap		Value
							($ in thousands)
October 1, 2008 thru December 31, 2008		87,400	$	63.42	$	83.86		(1,581	)
January 1, 2009 thru December 31, 2009		620,500	$	63.53	$	80.21		(15,664	)
January 1, 2010 thru October 31, 2010		486,400	$	63.44	$	78.26		(13,869	)

	M M Btu of		WAHA Gas Prices
	Natural Gas		Floor		Cap
October 1, 2008 through December 31, 2008		920,000	$	7.38	$	9.28		1,793
January 1, 2009 through December 31, 2009		3,285,000	$	7.06	$	9.93		1,534

Total Fair Market Value							$	(27,787	)

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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.

A recap for the period of time, number of barrels, swap prices and fair market values as of September 30, 2008 for these swaps follows:

Estimated

Number of

NyMex Oil

Fair Market

Period of Time

Barrels of Oil

Swap Price

Value

($ in thousands)

October 1, 2008 thru December 31, 2008

110,400

33.37

(7,353

)

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, 2008 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.

On April 14, 2008, we were added as a defendant to a lawsuit filed in 2007, styled Brady Briscoe vs. Capstar Drilling, L.P. (“Capstar”), Cause No. 21,287, in the 259th District Court of Jones County, Texas. The plaintiff has alleged that he was injured as the result of an accident while he was working, as an employee of an unrelated third party, on a drilling rig operated by Capstar. Capstar was conducting drilling operations for us. The plaintiff has asserted general allegations of negligence as to Capstar and, specifically, a failure to properly equip its drilling rig, further alleging we were in charge of the drilling rig and the operational details of the plaintiff’s work. The plaintiff has sued for an amount of actual damages of up to $15.0 million, together with pre-judgment interest, post-judgment interest and exemplary damages. Capstar recently settled with the plaintiff and Capstar has been dismissed from the lawsuit. If judgment is entered against us, we would be entitled to a credit for the amount that the plaintiff has already received from Capstar.

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If a judgment adverse to the defendants was entered, as a working interest owner in the leases comprising the unit, we believe our liability would be proportionate to the ownership of the other working interest owners in the leases. We have filed an answer denying any liability. Although an initial exchange of discovery has occurred, we cannot predict the ultimate outcome of this matter, we believe we have meritorious defenses and intend to vigorously contest this lawsuit. We have not established a reserve with respect to plaintiffs’ claims.

We received a Notice of Proposed Adjustment from the Internal Revenue Service, or the “Service” in May 2007 advising us of proposed adjustments to federal income tax of approximately $2.0 million for the years 2004 and 2005. Subsequent discussions with the Service placed the issues contested in a development status. In November 2007, the Service issued a letter on the matter giving the company 30 days to agree or disagree with a final examination report. The final examination report reflected revisions of the previous proposed adjustments resulting in a reduced $1.1 million of additional income tax and interest charges. The decrease in proposed tax was the result of information supplied by us to the examiner as well as discussions of the applicable tax statutes and regulations. In December 2007, we filed a protest documenting our complete disagreement with the adjustments proposed on the final examination report and requested a conference with the appeals office of the Service. The examination office of the Service filed a response to our protest in February 2008 with the appeals office. On June 4, 2008, our representatives met with the Service’s Appeals Officer to review specific issues related to our calculation of net income from oil and gas and the associated treatment of certain deductions. During this meeting we were advised that a request to issue an “advisory opinion” had been submitted to the National Office of the Service. Pending issuance of this advisory opinion, we will submit an amendment to our initial protest in further support of our position. We intend to vigorously contest the adjustment proposed by the Service and believe that we will ultimately prevail in our position. We have not recorded a liability for tax, interest, or penalties related to this matter based on our analysis. If a liability for additional income tax should later be determined to be more likely than not, we anticipate the adjustment to increase the federal income tax liability would be offset by an increase to a deferred tax asset and would not result in a charge to earnings. Any interest or penalties resulting from a subsequent determination of increased tax liability would require a charge to earnings. We believe that the effects of this matter would not have a material effect on our results of

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operations for the fiscal quarter in which we actually incur or establish a reserve account for interest or penalties.

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

ITEM 1A. RISK FACTORS

You should review and consider the information regarding certain factors which could materially affect our business, financial condition or future results set forth under Part I, Item 1A “Risk Factors” in our annual Report on Form 10-K for 2007. Except as set forth below, there have been no material changes during the quarter ended September 30, 2008, to the Risk Factors set forth in Part I, Item 1A of our Annual Report on Form 10-K for 2007.

General economic conditions could adversely impact our capital expenditure program which would affect our results of operations.

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

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

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

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

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

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liquidity may prove to be insufficient, and in such case, we may not be able to successfully obtain additional financing on favorable terms, or at all.

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

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

Our results of operations are materially affected by conditions in the domestic capital markets and the economy generally. The stress experienced by domestic capital markets that began in the second half of 2007 has continued and substantially increased during the third quarter of 2008. Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market and a declining real estate market in the U.S. have contributed to increased volatility and diminished expectations for the economy and the markets going forward. These factors, combined with volatile oil and gas prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and fears of a possible recession. In addition, the fixed-income markets are experiencing a period of extreme volatility which has negatively impacted market liquidity conditions.

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

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

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

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

The impairment of financial institutions could adversely affect us.

We have exposure to many different industries and counterparties, and routinely execute transactions with counterparties in the commercial banking industry. Many of these transactions expose us to credit risk in the event of default of our counterparty. In addition, with respect to our secured bank borrowings, our credit risk may be exacerbated when the collateral held by our lenders cannot be realized upon or is liquidated at prices not sufficient to recover the full amount of the loan due to it.

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

We use derivative instruments to mitigate our risks in various circumstances. We enter into a variety of derivative instruments, including swaps, puts and collars with a number of counterparties. See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” in our 2007 Form 10-K. If our counterparties fail or refuse to honor their obligations under these derivative instruments, our hedges of the related risk will be ineffective. This is a more pronounced risk to us in view of the recent stresses suffered by financial institutions. Such failure could have a material adverse effect on our financial condition and results of operations. We cannot provide assurance that our counterparties will honor their obligations now or in the future. A counterparty’s insolvency, inability or unwillingness to make payments required under terms of derivative instruments with us could have a material adverse effect on our financial condition and results of operations. At the date of filing this Form 10-Q Report with the Securities and Exchange Commission, our counterparties included Citibank, N.A. and BNP Paribas. As of September 30, 2008, we had a net derivative liability to Citibank, N.A. of $21.6 million and a net derivative liability to BNP Paribas of $13.4 million.

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

Our business, the value of our oil and natural gas properties and our revenues and profitability are substantially dependent on prevailing prices of oil and natural gas. Our ability to borrow and to obtain additional capital on attractive terms is also substantially dependent upon oil and natural gas prices. Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often causes disruption in the market for acquiring oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for acquisitions, development and exploitation projects. From September 30, 2006 thru September 30, 2008, oil prices have fluctuated from a low of approximately $51 to a high of approximately $145 per barrel for oil traded on the New York Mercantile Exchange (NYMEX). Subsequent to June 30, 2008, the prices of oil and natural gas traded on NYMEX have declined significantly. Between June 30, 2008 and October 27, 2008, oil prices have fallen 55% from $140 per barrel to $63.22 per barrel, and gas prices have fallen 54% from $13.35 per Mcf to $6.12 per Mcf. If commodity prices continue to decline to the point of reaching or falling below breakeven profitability levels, our financial condition and results of operation would be materially

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and adversely affected. In addition, any further and extended decline in the price of oil and natural gas could have an adverse effect on our business, the value of our properties, our borrowing capacity, revenues, profitability and cash flows from operations.

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 10.1 of the Registrant’s Current Report on Form 8-K filed on November 30, 2007)

3.3		Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

3.4		Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.4 of the Registrant’s Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

3.5		Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.5 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

3.6		Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.1		Certificate of Designations, Preferences and Rights of Serial Preferred Stock — 6% Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)

4.2		Certificate of Designations, Preferences and Rights of Series A Preferred Stock (Incorporated by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000)

4.3		Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the Registrant filed with the Securities and Exchange Commission on October 10, 2000)

4.4		Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No. 4.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.5		Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

4.6		Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

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No.		Description of Exhibit

4.7		Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American Stock Transfer, Inc. (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

4.8		First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant, Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

4.9		Form of Rule 144A 10¹/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

4.10		Form of IAI 10¹/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

4.11		Form of Regulation S 10¹/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

4.12		Indenture, dated as of July 31, 2007, among the Registrant as Issuer and Wells Fargo Bank, National Association as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

4.13		Registration Rights Agreement, dated as of July 31, 2007, by and among the Registrant, Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities Corp. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

4.14		Purchase Agreement, dated as of July 26, 2007, by and among the Registrant, Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities Corp. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

4.15		Form of 10¹/4% Unrestricted Senior Note due 2014 (Incorporated by reference to Exhibit 4.13 of Form S-4 of the Registrant, Registration No. 333-148465)

		Executive Compensation Plans and Arrangements (Exhibit No.’s 10.1 through 10.11):

10.1		1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

10.2		Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form 10-K for the fiscal year ended December 31, 1995)

10.3		Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005)

10.4		1998 Stock Option Plan (Incorporated by reference to Exhibit 10.4 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.5		2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form 10-Q Report for the fiscal quarter ended March 31, 2004)

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No.		Description of Exhibit

10.6		2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated September 22, 2004)

10.7		Incentive and Retention Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.8		2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated March 27, 2008)

10.9		Form of Nonqualified Stock Option Agreement for nonqualified stock options granted under the Registrant’s 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed on June 18, 2008)

10.10		Form of Outside Director Stock Award Agreement for stock awards granted under the Registrant’s 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K filed on June 18, 2008)

10.11		Form of Outside Director Restricted Stock Agreement for restricted stock grants under the Registrant’s 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K filed on June 18, 2008)

10.12		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)

10.13		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)

10.14		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)

10.15		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)

10.16		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)

10.17		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)

10.18		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)

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No.		Description of Exhibit

10.19		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)

10.20		Purchase and Sale Agreement, dated as of October 14, 2005, 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)

10.21		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)

10.22		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)

10.23		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)

10.24		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)

10.25		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)

10.26		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)

10.27		Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.23 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.28		Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.24 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.29		Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

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No.		Description of Exhibit

10.30		Third Amendment to Third Amended and Restated Credit Agreement, dated as of July 31, 2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

10.31		Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of November 30, 2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to Exhibit 10.27 of Form S-4 of the Registrant, Registration No. 333-148465)

10.32		Hagerman Gas Gathering System Joint Venture Agreement, dated as of January 16, 2007, among the Registrant, Feagan Gathering Company and Capstone Oil and Gas Company, L.P. (Incorporated by reference to Exhibit 10.28 of Form 10-K of the Registrant for the fiscal year ended December 31, 2007)

10.33		Fourth Amended and Restated Credit Agreement, dated as of May 16, 2008, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland plc, and Texas Capital Bank, N.A. (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on May 22, 2008)

*10.34		First Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 31, 2008, by and among Parallel Petroleum Corporation, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Bank of Scotland plc, Texas Capital Bank, N.A., Bank of America, N.A. and West Texas National Bank

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)

*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.

(55)

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 3, 2008	Larry C. Oldham
	President and Chief Executive Officer


Date: November 3, 2008	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 10.1 of the Registrant’s Current Report on Form 8-K filed on November 30, 2007)

3.3		Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

3.4		Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.4 of the Registrant’s Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

3.5		Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.5 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

3.6		Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No. 3.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.1		Certificate of Designations, Preferences and Rights of Serial Preferred Stock — 6% Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2004)

4.2		Certificate of Designations, Preferences and Rights of Series A Preferred Stock (Incorporated by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000)

4.3		Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the Registrant filed with the Securities and Exchange Commission on October 10, 2000)

4.4		Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No. 4.6 of the Registrant’s Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004)

4.5		Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

4.6		Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

4.7		Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American Stock Transfer, Inc. (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

4.8		First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant, Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A.


No.		Description of Exhibit

		(Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

4.9		Form of Rule 144A 10¹/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

4.10		Form of IAI 10¹/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

4.11		Form of Regulation S 10¹/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

4.12		Indenture, dated as of July 31, 2007, among the Registrant as Issuer and Wells Fargo Bank, National Association as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

4.13		Registration Rights Agreement, dated as of July 31, 2007, by and among the Registrant, Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities Corp. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

4.14		Purchase Agreement, dated as of July 26, 2007, by and among the Registrant, Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities Corp. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

4.15		Form of 10¹/4% Unrestricted Senior Note due 2014 (Incorporated by reference to Exhibit 4.13 of Form S-4 of the Registrant, Registration No. 333-148465)

		Executive Compensation Plans and Arrangements (Exhibit No.’s 10.1 through 10.11):

10.1		1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004)

10.2		Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form 10-K for the fiscal year ended December 31, 1995)

10.3		Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005)

10.4		1998 Stock Option Plan (Incorporated by reference to Exhibit 10.4 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.5		2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form 10-Q Report for the fiscal quarter ended March 31, 2004)

10.6		2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated September 22, 2004)

10.7		Incentive and Retention Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)


No.		Description of Exhibit

10.8		2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K Report dated March 27, 2008)

10.9		Form of Nonqualified Stock Option Agreement for nonqualified stock options granted under the Registrant’s 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed on June 18, 2008)

10.10		Form of Outside Director Stock Award Agreement for stock awards granted under the Registrant’s 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K filed on June 18, 2008)

10.11		Form of Outside Director Restricted Stock Agreement for restricted stock grants under the Registrant’s 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K filed on June 18, 2008)

10.12		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)

10.13		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)

10.14		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)

10.15		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)

10.16		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)

10.17		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)

10.18		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)

10.19		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)


No.		Description of Exhibit

10.20		Purchase and Sale Agreement, dated as of October 14, 2005, 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)

10.21		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)

10.22		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)

10.23		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)

10.24		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)

10.25		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)

10.26		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)

10.27		Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.23 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.28		Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.24 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.29		Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended December 31, 2006)

10.30		Third Amendment to Third Amended and Restated Credit Agreement, dated as of July 31, 2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank,


No.		Description of Exhibit

		Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K filed on August 1, 2007)

10.31		Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of November 30, 2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to Exhibit 10.27 of Form S-4 of the Registrant, Registration No. 333-148465)

10.32		Hagerman Gas Gathering System Joint Venture Agreement, dated as of January 16, 2007, among the Registrant, Feagan Gathering Company and Capstone Oil and Gas Company, L.P. (Incorporated by reference to Exhibit 10.28 of Form 10-K of the Registrant for the fiscal year ended December 31, 2007)

10.33		Fourth Amended and Restated Credit Agreement, dated as of May 16, 2008, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland plc, and Texas Capital Bank, N.A. (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on May 22, 2008)

*10.34		First Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 31, 2008, by and among Parallel Petroleum Corporation, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Bank of Scotland plc, Texas Capital Bank, N.A., Bank of America, N.A. and West Texas National Bank

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)

*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.