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

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

PARALLEL PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware		75-1971716
(State of other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

(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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o No o

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

     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 ¨ No ¨

     As of July 30, 2009, the registrant had 41,646,445 shares of common stock outstanding.

 

 

INDEX

				Page No.
		PART I. FINANCIAL INFORMATION
ITEM 1.		FINANCIAL STATEMENTS
		Reference is made to the succeeding pages for the following financial statements:
		— Unaudited Balance Sheets at June 30, 2009 and December 31, 2008			1
		— Unaudited Statements of Operations for the three months and six months ended June 30, 2009 and 2008			3
		— Unaudited Statements of Stockholders’ Equity as of December 31, 2008 and for the six months ended June 30, 2009			4
		— Unaudited Statements of Cash Flows for the six months ended June 30, 2009 and 2008			5
		— Notes to Financial Statements			7
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			24
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			48
ITEM 4.		CONTROLS AND PROCEDURES			51
		PART II — OTHER INFORMATION
ITEM 1.		LEGAL PROCEEDINGS			52
ITEM 1A.		RISK FACTORS			53
ITEM 2.		UNREGISTERED SALES OR EQUITY SECURITIES AND USE OF PROCEEDS			59
ITEM 4.		SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			60
ITEM 5.		OTHER INFORMATION			60
ITEM 6.		EXHIBITS			60
SIGNATURES
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART 1 — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PARALLEL PETROLEUM CORPORATION
Balance Sheets
(unaudited)
($ in thousands)

Assets

		June 30,				December 31,
		2009				2008
Current assets:
Cash and cash equivalents		$	28,774			$	36,303
Short-term investments			5,000				5,002
Accounts receivable:
Oil and natural gas sales			10,084				13,399
Joint interest owners and other, net of allowance for doubtful account of $50			1,596				2,805
Affiliates and joint ventures			6				12
			11,686				16,216
Other current assets			702				430
Derivatives			8,825				22,665
Total current assets			54,987				80,616
Property and equipment, at cost:
Oil and natural gas properties, full cost method (including $136,046 and $137,202 not subject to depletion)			888,676				878,722
Other			3,314				3,172
			891,990				881,894
Less accumulated depreciation, depletion and amortization			(533,171	)			(490,566	)
Net property and equipment			358,819				391,328
Restricted cash			82				81
Investment in pipeline venture			349				337
Other assets, net of accumulated amortization of $1,754 and $1,443			3,312				3,566
Deferred tax asset			71,336				60,567
Derivatives			8,616				14,081
		$	497,501			$	550,576

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

PARALLEL PETROLEUM CORPORATION
Balance Sheets (continued)
(unaudited)
($ in thousands)

Liabilities and Stockholders’ Equity

		June 30,				December 31,
		2009				2008
Current liabilities :
Accounts payable trade		$	2,103			$	13,522
Accrued liabilities			14,423				21,780
Accrued interest on senior notes			6,406				6,407
Asset retirement obligations			158				158
Derivative obligations			4,737				3,004
Put premium obligations			1,036				628
Deferred tax liability			1,058				6,597
Total current liabilities			29,921				52,096
Long-term liabilities:
Revolving credit facility			225,000				225,000
Senior notes (principal amount $150,000)			146,166				145,890
Asset retirement obligations			9,846				11,221
Derivative obligations			5,041				5,136
Put premium obligations			3,031				3,655
Termination obligation			385				532
Total long-term liabilities			389,469				391,434
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 for 2009 and 2008			415				415
Additional paid-in capital			201,198				200,132
Retained deficit			(123,502	)			(93,501	)
Total stockholders’ equity			78,111				107,046
		$	497,501			$	550,576

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

PARALLEL PETROLEUM CORPORATION
Statements of Operations
(unaudited)
(in thousands, except per share data)

		Three Months Ended June 30,								Six Months Ended June 30,
		2009				2008				2009				2008
Oil and natural gas revenues:
Oil and natural gas sales		$	19,861			$	56,075			$	38,090			$	100,016
Costs and expenses:
Lease operating expense			5,541				7,254				13,627				14,233
Production taxes			761				2,996				1,334				5,285
General and administrative			3,281				3,265				6,714				5,833
Depreciation, depletion and amortization			5,398				10,483				12,179				19,835
Impairment of oil and natural gas properties			—				—				30,426				—
Total costs and expenses			14,981				23,998				64,280				45,186
Operating income (loss)			4,880				32,077				(26,190	)			54,830
Other income (expense), net:
Loss on derivatives not classified as hedges			(13,286	)			(71,609	)			(7,521	)			(93,495	)
Interest and other income			30				32				99				65
Interest expense, net of capitalized interest			(6,360	)			(5,368	)			(12,690	)			(10,886	)
Other expense			(5	)			(1	)			(5	)			(1	)
Equity in gain of pipelines and gathering system ventures			—				165				1				382
Total other income (expense), net			(19,621	)			(76,781	)			(20,116	)			(103,935	)
Loss before income taxes			(14,741	)			(44,704	)			(46,306	)			(49,105	)
Income tax benefit			5,101				15,499				16,305				17,160
Net loss		$	(9,640	)		$	(29,205	)		$	(30,001	)		$	(31,945	)
Net loss per common share:
Basic		$	(0.23	)		$	(0.70	)		$	(0.72	)		$	(0.77	)
Diluted		$	(0.23	)		$	(0.70	)		$	(0.72	)		$	(0.77	)
Weighted average common shares outstanding:
Basic			41,597				41,446				41,597				41,359
Diluted			41,597				41,446				41,597				41,359

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

PARALLEL PETROLEUM CORPORATION
Statements of Stockholders’ Equity
As of December 31, 2008 and for the six months ended June 30, 2009
(unaudited)
(in thousands)

		Common stock								Additional								Total
		Number of								paid-in				Retained				stockholders’
		shares				Amount				capital				deficit				equity
Balance, December 31, 2008			41,597			$	415			$	200,132			$	(93,501	)		$	107,046
Restricted stock expense			—				—				45				—				45
Stock option expense			—				—				1,021				—				1,021
Net loss			—				—				—				(30,001	)			(30,001	)
Balance, June 30, 2009			41,597			$	415			$	201,198			$	(123,502	)		$	78,111

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

PARALLEL PETROLEUM CORPORATION
Statements of Cash Flows
Six Months Ended June 30, 2009 and 2008
(unaudited)
($ in thousands)

		2009				2008
Cash flows from operating activities:
Net loss		$	(30,001	)		$	(31,945	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization			12,179				19,835
Gain on sale of automobiles			—				(4	)
Impairment of oil and natural gas properties			30,426				—
Accretion of asset retirement obligation			425				187
Accretion of senior notes discount			276				247
Deferred income tax benefit			(16,305	)			(17,160	)
Loss on derivatives not classified as hedges			7,521				93,495
Amortization of deferred financing cost			312				374
Accretion of interest on put obligations			105				6
Common stock issued to directors			—				160
Restricted stock expense			45				57
Stock option expense			1,021				227
Equity in gain of pipelines and gathering system ventures			(1	)			(382	)
Changes in assets and liabilities:
Other assets, net			632				(854	)
Restricted cash			(1	)			(2	)
Accounts receivable			4,530				(8,316	)
Other current assets			(272	)			(99	)
Accounts payable and accrued liabilities			(11,380	)			14,069
Net cash (used in) provided by operating activities			(488	)			69,895
Cash flows from investing activities:
Additions to oil and natural gas properties			(19,301	)			(123,727	)
Additions to other property and equipment			(142	)			(273	)
Settlements on derivative instruments			10,785				(22,839	)
Short-term investments			(5,000	)			—
Maturity of short-term investments			5,002				—
Net investment in pipelines and gathering system ventures			(11	)			(15	)
Net cash used in investing activities			(8,667	)			(146,854	)
Cash flows from financing activities:
Borrowings from bank line of credit			—				77,000
Deferred financing cost			(690	)			(270	)
Proceeds from exercise of stock options			—				1,323
Settlements on derivative instruments with financing elements			2,316				—
Net cash provided by financing activities			1,626				78,053
Net (decrease) increase in cash and cash equivalents			(7,529	)			1,094
Cash and cash equivalents at beginning of period			36,303				7,816
Cash and cash equivalents at end of period		$	28,774			$	8,910

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

Parallel Petroleum Corporation
Statements of Cash Flows (continued)
Six Months Ended June 30, 2009 and 2008
(unaudited)
($ in thousands)

		2009				2008
Non-cash financing and investing activities:
Deferred purchase of derivative puts		$	—			$	3,325
Oil and natural gas properties asset retirement obligations		$	(1,800	)		$	482
Additions to oil and natural gas properties accrued		$	(7,400	)		$	1,000
Termination obligation capitalized to oil and natural gas properties		$	(147	)		$	—
Property transfer:
Transfer to oil and natural gas properties		$	—			$	8,707
Transfer from equity investment		$	—			$	(8,707	)
Other transactions:
Interest paid		$	13,040			$	9,901
Taxes paid		$	75			$	—

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

NOTES TO FINANCIAL STATEMENTS

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

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

     Parallel is engaged in the acquisition, development and exploitation of long-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, 2008 has been derived from our audited Financial Statements as of December 31, 2008. 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 2008 amounts have been conformed to the 2009 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 Financial Statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2008.

     Unless otherwise indicated or unless the context otherwise requires, all references to “we”, “us”, “our”, “Parallel”, or “Company” mean the registrant, Parallel Petroleum Corporation.

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)).

     Parallel awards incentive stock options, nonqualified stock options, restricted stock and stock awards to selected key employees, officers, and directors. Stock options are awarded at exercise prices equal to the closing price of our common stock on the date of grant. These options vest over a period of two to ten years with a ten-year exercise period. As of June 30, 2009, options expire beginning in 2011 and extending through 2019. The stock options and restricted stock awards’ fair values are described below for each grant. Stock based compensation expense is classified as a general and administrative expense in the Statements of Operations.

     Options

     For the three months ended June 30, 2009 and 2008, we recognized compensation expense of approximately $499,000 and $145,000, respectively, with a tax benefit of approximately $170,000 and $49,000, respectively. For the six months ended June 30, 2009 and 2008, we recognized compensation expense of approximately $1.0 million and $227,000, respectively, with a tax benefit of approximately

$347,000 and $77,000, respectively, associated with our stock option grants.

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

		Future
		Compensation
		Expense
		($ in thousands)
Third quarter 2009		$	352
Fourth quarter 2009			345
2010			999
2011			486
2012			159
2013			14
Total		$	2,355

     At June 30, 2009, options to purchase 397,750 shares of common stock were outstanding and vested. At that same date, options to purchase 805,450 shares were outstanding and unvested. During the six months ended June 30, 2009, options to purchase 464,200 shares were granted to officers and employees, and none of the options expired or were forfeited.

     The fair value of each option award is estimated on the date of grant. The fair values of stock options granted prior to and outstanding at June 30, 2009 and that covered shares subject to future vesting at that date were determined using the Black-Scholes option valuation method from traded options and historical volatility of our stock. The expected term of the options used in the Black-Scholes model represents 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.

		2009				2008				2005				2001
Expected volatility			63.94	%			46.50	%			54.20	%			57.95	%
Expected dividends			0.00				0.00				0.00				0.00
Expected term (in years)			6.25				6.25				6.5				7.5
Risk-free rate			3.19	%			3.81%-3.86	%			4.20	%			5.05	%

     A summary of the stock option activity for the six months ended June 30, 2009 is presented below:

										Weighted
										Average
		Number of Shares of				Weighted				Remaining
		Common Stock				Average Exercise				Contractual				Aggregate
		Underlying Options				Price				Term				Intrinsic Value
		(in thousands)								(years)				($ in thousands)
Outstanding December 31, 2008			739			$	14.41
Granted			464			$	2.00
Exercised			—			$	—
Surrendered			—			$	—
Outstanding June 30, 2009			1,203			$	9.62				9.0			$	—
Exercisable at June 30, 2009			398			$	10.66				7.3			$	—

		($ in thousands)
Average weighted grant date fair value of options issued and unvested, June 30, 2009		$	3,879
Average weighted grant date fair value of options issued and outstanding, June 30, 2009		$	6,191

     Restricted Stock

     For the three months ended June 30, 2009 and 2008, we recognized compensation expense of approximately $21,000 and $57,000, with a tax benefit of approximately $7,000 and $19,000, respectively, for restricted stock. For the six months ended June 30, 2009 and 2008, we recognized compensation expense of approximately $45,000 and $57,000, respectively, with a tax benefit of approximately $15,000 and $19,000, respectively, for restricted stock.

     The fair value of restricted stock awards granted are based on the last sales price of our common stock on the Nasdaq Global market on the date of the grant.

NOTE 3.		CREDIT ARRANGEMENTS

     We maintain one credit facility, our Fourth Amended and Restated Credit Agreement, or the “Revolving Credit Agreement”, dated May 16, 2008, as amended on April 30, 2009, which we describe below.

     Revolving Credit Facility

     Our Revolving Credit Agreement with a group of bank lenders provides us with a revolving line of credit having a “borrowing base” limitation of $230.0 million at June 30, 2009. 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 June 30, 2009, the principal amount outstanding under our revolving credit facility was $225.0 million, excluding $445,000 reserved for our letters of credit. The Revolving Credit Agreement allows us to borrow, repay and reborrow amounts available under the 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. The April 30, 2009 amendment reaffirmed our borrowing base of $230.0 million and changed the funded debt ratio we are required to maintain as described below. If the outstanding principal amount of our loans ever exceeds the borrowing base, we must either provide additional collateral to the lenders or repay the outstanding principal of our loans in an amount equal to the excess. Except for 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 June 30, 2009, our group of bank lenders included Citibank, N.A., BNP Paribas, Compass Bank, Bank of Scotland plc, Bank of America, N.A., Texas Capital Bank, N.A., Western National Bank and West Texas National Bank. None of the bank lenders held more than 21% of the facility at June 30, 2009.

     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.

     The base rate is generally equal to the sum of (a) Citibank’s “prime rate” as announced by it from time to time plus (b) a margin ranging from zero to 0.50%, the amount of which depends 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 0.50%. If the principal amount outstanding is equal to or greater than 50% but less than 75% of the borrowing base, the margin is 0.25%. If the borrowing base usage is less than 50%, there is no margin percent.

     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 2.75% to 3.25%, depending upon the outstanding principal amount of our loan. As amended on April 30, 2009, LIBOR margin means if the principal amount outstanding is equal to or greater than 75% of the borrowing base, the margin is 3.25%. If the principal amount outstanding is equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 3.00%. If the principal amount outstanding is less than 50% of the borrowing base, the margin is 2.75%.

     The interest rate we are required to pay on our borrowings, including the applicable margin, may never be less than 4.75%. At June 30, 2009, our base rate, plus the applicable margin, was 4.75% on $225.0 million, the outstanding principal amount of our revolving loan on that same date.

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

     If the total outstanding borrowings under the revolving credit facility are less than the borrowing base, we are required to pay an unused commitment fee to the lenders in an amount equal to 0.25% 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 0.375% on the amount of any increase.

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

     The Revolving Credit Agreement contains customary 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 (“EBITDA”), (iii) maintenance of a minimum net worth, (iv) prohibition of payment of dividends and (v) restrictions on incurrence of additional debt. As amended on April 30, 2009, our ratio of Consolidated Funded Debt to Consolidated EBITDA may not exceed 5.00 to 1.00 during 2009, 4.25 to 1.00 during 2010 or 4.00 to 1.00 during 2011 and thereafter.

     We have pledged substantially all of our producing oil and natural gas properties to secure the repayment of our indebtedness under the revolving credit facility. If we breach any of the provisions of the credit agreement, including the financial covenants, and are unable to obtain waivers from our lenders, they would be entitled to declare an event of default, at which point the entire unpaid principal balance of the loans, together with all accrued and unpaid interest, would become immediately due and payable. Because substantially all of our assets are pledged as collateral under the revolving facility, if our lenders declare an event of default, they would be entitled to foreclose on and take possession of our assets.

     In addition to the restrictive covenants contained in the Revolving Credit Agreement, our lenders have the unilateral authority to redetermine the borrowing base at any time they desire to do so. Any such unscheduled redetermination could result in the requirement for us to provide additional collateral or repay any borrowing base deficiency as described above. Although our lenders have not, in the past, initiated an unscheduled borrowing base determination, current economic conditions could cause the lenders to initiate such an unscheduled redetermination.

     As of June 30, 2009 we were in compliance with the covenants in our Revolving Credit Agreement.

     Senior Notes

     At June 30, 2009, the carrying value of our $150.0 million 10¹/4 % senior notes due 2014, or “senior notes”, was $146.2 million and their estimated fair value is approximately $104.3 million based on market trades at or near June 30, 2009. The senior notes mature on August 1, 2014 and bear interest at 10.25%, per annum on the principal amount. Interest is payable semi-annually on February 1 and August 1 of each year to holders of record at the close of business on the preceding January 15 and July 15, respectively, and payments commenced 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 or (b) the excess of the present value of the redemption price of such notes as of August 1, 2011 plus all required interest payments due through August 1, 2011 (computed at a discount rate equal to a specified U.S. “Treasury Rate” plus 50 basis points), over the principal amount of the senior notes being redeemed. If we experience a change of control, we will be required to make an offer to repurchase the senior notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

     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 June 30, 2009 we were in compliance with the covenants in the Indenture.

     Interest Incurred

     For the six months ended June 30, 2009 and 2008, the aggregate interest incurred under our revolving credit facility and our senior notes was approximately $13.0 million and $10.3 million, respectively. Deferred financing costs and note discount amortization were approximately $588,000 and $621,000 and capitalized interest was approximately $1.0 million and $44,000 for the six months ended June 30, 2009 and 2008, respectively.

NOTE 4.		OIL AND NATURAL GAS PROPERTIES

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

	•		all wells drilled from November 1, 2008 through December 31, 2009, and all wells drilled during each succeeding calendar year through 2016 will be treated as a separate project or payout period, creating eight separate projects or payout periods;
	•		at the time Chesapeake commences the drilling of a well during one of the payout periods, we will assign to Chesapeake 100% of our leasehold interest within the subject unit or lease, reserving and retaining a 50% reversionary interest that will vest after Chesapeake recovers 150% of its costs for a particular payout period. Until 150% payout has been reached, Chesapeake will fund 100% of our costs for drilling, completing and operating wells during the payout period;

	•		on each project, Chesapeake is entitled to receive all revenues from our reversionary interest until Chesapeake receives revenues totaling 150% of the drilling, completion and operating costs Chesapeake incurs in funding our reversionary interest;
	•		upon reaching the 150% payout level for a given project, 50% of the interest assigned to Chesapeake will revert back to us;
	•		after 150% project payout, we will pay all costs and receive all revenues attributable to our 50% reversionary interest in each project;
	•		for wells drilled after January 1, 2017, we will pay all costs and receive all revenues attributable to our 50% reversionary interest; and
	•		we retained all of our interest in wells commenced prior to November 1, 2008, except for 3 wells commenced in late October 2008. We also retained all of our interest in approximately 90 gross (22.4 net) producing wells and 31 gross (9.49 net) wells in progress.

     As non-operator, we do not control the timing of investment in the Barnett Shale gas project. For this reason, we entered into the farmout agreement. The farmout agreement had minimal effect on our proved reserves as of June 30, 2009 and December 31, 2008.

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

     We use the full cost method to account for our oil and natural gas producing activities. Under the full cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling limitation is the discounted estimated after-tax future net cash flows from proved oil and natural gas properties. The net book value of oil and natural gas properties, less related deferred income taxes, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less related deferred income taxes, is generally written off as an expense.

     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 six months ended June 30, 2009 and 2008, overhead costs capitalized were approximately $680,000 and $842,000, respectively.

     We have recognized an impairment of approximately $30.4 million during the six months ended June 30, 2009. We did not recognize an impairment in the quarter ended June 30, 2009 or in the six months ended June 30, 2008. We cannot assure you that we will not experience further impairments in the future.

     The following table reflects capitalized costs related to the oil and natural gas properties as of June 30, 2009 and December 31, 2008.

		June 30,				December 31,
		2009				2008
		($ in thousands)
Proved properties		$	752,630			$	741,520
Unproved properties, not subject to depletion			136,046				137,202
			888,676				878,722
Accumulated depletion (1)			(530,596	)			(488,168	)
		$	358,080			$	390,554

NOTE 5.		OTHER ASSETS

     Below are the components of other assets as of June 30, 2009 and December 31, 2008.

		June 30,				December 31,
		2009				2008
		($ in thousands)
Revolving credit facility deferred financing costs, net		$	1,813			$	1,306
Senior notes deferred financing costs, net			1,304				1,432
Other			195				828
		$	3,312			$	3,566

NOTE 6.		OTHER ACCRUED LIABILITIES

     Below are the components of other accrued liabilities as of June 30, 2009 and December 31, 2008.

		June 30,				December 31,
		2009				2008
		($ in thousands)
Revenue payable to joint interest and royalty owners		$	6,675			$	8,004
Accrued capital expenditures			1,566				9,275
Accrued lease operating expense			1,856				2,223
Accrued ad valorem taxes			2,038				150
Other			2,288				2,128
		$	14,423			$	21,780

NOTE 7.		ASSET RETIREMENT OBLIGATIONS

     The following table summarizes our asset retirement obligation transactions for the periods indicated:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
		($ in thousands)								($ in thousands)
Beginning asset retirement obligation		$	11,429			$	5,802			$	11,379			$	4,937
Additions related to new properties			6				554				121				706
Revisions in estimated cash flows			(1,643	)			(851	)			(1,715	)			(209	)
Deletions related to property disposals			(3	)			(3	)			(206	)			(15	)
Accretion expense			215				104				425				187
Ending asset retirement obligation		$	10,004			$	5,606			$	10,004			$	5,606

     The adoption of FAS 157 on non-financial assets and liabilities related to our asset retirement obligations had an immaterial impact on our balance sheet as of June 30, 2009 and our results of operations for the three and six months ended June 30, 2009. Our asset retirement obligation is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs and well life. The inputs are calculated based on historical data as well as current estimated costs.

NOTE 8.		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 volatility 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.

     Our put contracts contain a financing element, which management believes is other than insignificant, resulting in related cash settlements being classified as cash from financing activities within the Statement of Cash Flows. These settlements are disclosed as net settlements to reflect the amount of the gross settlement less the amount of the original put premium for the specific contracts being settled.

     All derivative contracts 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. We actively monitor our credit risks related to financial institutions and counterparties including monitoring credit agency ratings, financial position and current news to mitigate this credit risk. We minimize credit risk in derivative instruments by entering into transactions with counterparties that are parties to our credit facility. See “Item 1A. Risk Factors” for additional discussion concerning the risk with counterparties of the derivative instruments.

     Adoption of SFAS No. 161

     We adopted SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133 (“SFAS 161”), effective January 1, 2009 for all financial assets and liabilities. SFAS 161 requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves transparency of financial reporting. Entities are required to provide enhanced disclosure about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flow.

     The tables below provide the fair values of the derivative instruments and their gains and losses located on the Balance Sheet and Statement of Operations as of June 30, 2009.

Fair Values of Derivative Instruments on the Balance Sheet
Derivatives not Designated as Hedging Instruments under Statement 133

		As of
		June 30, 2009				December 31, 2008
		($ in thousands)
Derivative Asset
Gas swaps		$	210			$	—
Gas collars			5,418				6,611
Oil collars			1,660				13,480
Oil puts			10,153				16,655
Derviative Obligation
Interest rate swaps			(6,616	)			(8,051	)
Gas collars			(1,475	)			—
Oil collars			(1,687	)			(89	)
Net derivative asset		$	7,663			$	28,606

The Effect of Derivative Instruments on the Statement of Operations
Derivatives not Designated as Hedging Instruments under Statement 133⁽¹⁾

		For the three months ended								For the six months ended
		June 30, 2009				June 30, 2008				June 30, 2009				June 30, 2008
		($ in thousands)								($ in thousands)
Interest rate swaps		$	457			$	1,407			$	(23	)		$	(695	)
Gas collars			(1,040	)			(9,147	)			3,482				(13,712	)
Gas swaps			175				—				537				—
Oil swaps			—				(11,847	)			—				(14,886	)
Oil collars			(8,983	)			(51,597	)			(7,652	)			(63,777	)
Oil puts			(3,895	)			(425	)			(3,865	)			(425	)
Total loss on derivatives		$	(13,286	)		$	(71,609	)		$	(7,521	)		$	(93,495	)

     Adoption of SFAS No. 157

     We adopted SFAS No. 157, Fair Value Measurements (“SFAS 157”), effective January 1, 2008 for all financial assets and liabilities. Beginning January 1, 2009, we also applied SFAS No. 157 to non-financial assets and liabilities. 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). In determining the fair value of its derivative contracts the Company evaluates its counterparty and third party service provider valuations and adjusts for credit risk when appropriate. We use historical prices for volatility assumptions, future market prices and treasury rates as inputs to value the oil, natural gas and interest rate derivatives. SFAS 157 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires that 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.
	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 are valued 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. These instruments are considered Level 3 because we do not have sufficient corroborating market evidence for volatility to support classifying these 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 assets (liabilities) by SFAS No. 157 valuation levels as of June 30, 2009 (in thousands):

		Quoted Prices in
		Active Markets
		for Identical				Other Observable				Unobservable				Fair Value at
		Assets (Level 1)				Inputs (Level 2)				Inputs (Level 3)				June 30, 2009
Interest swaps		$	—			$	(6,616	)		$	—			$	(6,616	)
Gas swaps		$	—			$	210			$	—			$	210
Oil puts		$	—			$	—			$	10,153			$	10,153
Oil & gas collars		$	—			$	—			$	3,916			$	3,916
		$	—			$	(6,406	)		$	14,069			$	7,663

     The determination of the fair values above incorporates various factors required under SFAS No. 157. These factors include the impact of our nonperformance risk and the credit standing of the counterparties involved in our derivative contracts. The risk of nonperformance by our counterparties is mitigated by the fact that such counterparties (or their affiliates) are also bank lenders under our Revolving Credit Agreement and the derivative instruments with these counterparties allow us to setoff amounts owed by the counterparty to it against any obligation we owe the counterparty under our Revolving Credit Agreement.

     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								Six Months Ended
		June 30, 2009								June 30, 2009
		Derivative				Derivative				Derivative				Derivative
		Collars				Puts				Collars				Puts
Beginning balance		$	18,887			$	15,160			$	20,002			$	16,656
Total losses			(10,024	)			(3,904	)			(4,170	)			(3,867	)
Settlements(1)			(4,947	)			(1,103	)			(11,916	)			(2,636	)
Purchases			—				—				—				—
Transfers in and/or out of level 3			—				—				—				—
Balance at end of period		$	3,916			$	10,153			$	3,916			$	10,153
Change in unrealized losses included in earnings relating to derivatives still held as of June 30, 2009(2)		$	(14,971	)		$	(5,007	)		$	(16,086	)			(6,503	)

     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 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 entered into interest rate swap contracts with BNP Paribas and Citibank, N.A. (the “counterparties”) which are intended to have the effect of converting variable rate interest payments required to be made on our Revolving Credit Agreement to fixed interest rates for the periods covered by the swaps. Under terms of these swap contracts, in periods during which the fixed interest rate stated in the swap contract exceeds the variable rate (which is based on a 90-day LIBOR rate) we pay to the counterparties an amount determined by applying this excess fixed rate to the notional amount of the contract. In periods when the variable rate exceeds the fixed rate stated in the swap contracts, the counterparties pay an amount to us determined by applying the excess of the variable rate over the stated fixed rate to the notional amount of the contract. These contracts are accounted for by “mark-to-market” accounting as prescribed in SFAS 133. We have historically viewed these contracts as additional protection against future interest rate volatility. As of June 30, 2009, the fair market value of these interest rate swaps was a liability of approximately $6.6 million.

     The table below recaps the terms of these interest rate swaps and the fair market value of these contracts as of June 30, 2009.

		Notional				Weighted Average				Estimated
Period of Time		Amounts				Fixed Interest Rates				Fair Market Value
		($ in millions)								($ in thousands)
July 1, 2009 through December 31, 2009		$	100				4.22	%		$	(1,798	)
January 1, 2010 through October 31, 2010		$	100				4.71	%			(2,777	)
November 1, 2010 through December 31, 2010		$	50				4.26	%			(237	)
January 1, 2011 through December 31, 2011		$	100				4.67	%			(1,804	)
Total Fair Market Value										$	(6,616	)

Commodity Price Sensitivity

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

     Put Options. Puts are options to sell an asset at a specified price. 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 and in October 2008 we entered into a put contract with Citibank, N.A. 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 $4.68 million which is $491,000 greater than if the premiums had been paid at the time of entering into the contracts. The $491,000 difference is recorded as a discount to the put premium obligations and recognized as interest expense over the terms of the contracts using the effective interest method. Through June 30, 2009, we had accrued approximately $183,000 of interest expense and settled premiums of approximately $320,000. Accordingly, the recorded balance of the put premium obligations at June 30, 2009 is approximately $4.1 million.

     A summary of our put positions at June 30, 2009 is as follows:

										Estimated
		Barrels of								Fair Market
Period of Time		Oil				Floor				Value
										($ in thousands)
July 1, 2009 through December 31, 2009			55,200			$	100.00			$	1,575
January 1, 2010 through December 31, 2010			280,100			$	84.36				4,709
January 1, 2011 through December 31, 2011			146,000			$	100.00				3,869
Total Fair Market Value										$	10,153

     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.

     On April 8, 2009, we executed a natural gas costless collar trade for 2,000 MMBtu/day (WAHA) for calendar year 2010 with a floor of $4.70 and a ceiling of $5.65 with a total volume of 730,000 MMBtu. We also executed a second natural gas costless collar trade for 5,000 MMBtu/day (WAHA) for the three months of October, November and December 2009 with a floor of $3.60 and a ceiling of $4.10 with a total volume of 460,000 MMBtu.

     On June 15, 2009, we executed an oil costless collar trade for 700 Bbl/day oil (WTI-NYMEX) for calendar year 2011 with a floor of $70.00 and a ceiling of $94.25 with a total volume of 255,500 Bbl. We also executed a second oil costless collar trade for 1,000 Bbl/day oil (WTI-NYMEX) for calendar 2012 with a floor of $70.00 and a ceiling of $101.50 with a total volume of 366,000 Bbl.

     A summary of our collar positions at June 30, 2009 is as follows:

														Estimated
		Barrels of				NYMEX Oil Prices								Fair Market
Period of Time		Oil				Floor				Ceiling				Value
														($ in thousands)
July 1, 2009 through December 31, 2009			386,400			$	65.71			$	82.93			$	417
January 1, 2010 through October 31, 2010			486,400			$	63.44			$	78.26				(1,503	)
January 1, 2011 through December 31, 2011			255,500			$	70.00			$	94.50				424
January 1, 2012 through December 31, 2012			366,000			$	70.00			$	101.50				634
		MMBtu of				WAHA Gas Prices
		Natural Gas				Floor				Ceiling
July 1, 2009 through December 31, 2009			2,116,000			$	6.30			$	8.66				5,246
January 1, 2010 through December 31, 2010			4,380,000			$	4.74			$	5.86				(1,302	)
Total Fair Market Value														$	3,916

     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, MMBtu quantities and swap prices are as follows:

Estimated

MMBtu of

WAHA

Fair Market

Period of Time

Natural Gas

Swap Price

Value

($ in thousands)

July 1, 2009 through September 30, 2009

460,000

$

3.91

$

210

NOTE 9. NET LOSS 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 loss per share for the three and six months ended June 30, 2009 and 2008:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
		(in thousands, except per share data)
Basic EPS Computation:
Numerator-
Net loss		$	(9,640	)		$	(29,205	)		$	(30,001	)		$	(31,945	)
Denominator-
Weighted average common shares outstanding			41,597				41,446				41,597				41,359
Basic EPS:
Net loss per share		$	(0.23	)		$	(0.70	)		$	(0.72	)		$	(0.77	)
Diluted EPS Computation:
Numerator-
Net loss		$	(9,640	)		$	(29,205	)		$	(30,001	)		$	(31,945	)
Denominator-
Weighted average common shares outstanding			41,597				41,446				41,597				41,359
Employee stock options			—				—				—				—
Warrants			—				—				—				—
Weighted average common shares for diluted earnings per share assuming conversion			41,597				41,446				41,597				41,359
Diluted EPS:
Net loss per share		$	(0.23	)		$	(0.70	)		$	(0.72	)		$	(0.77	)

     For the three and six months ended June 30, 2009 and 2008, the effects of all potentially dilutive securities (including options and warrants) were excluded from the computation of diluted earnings per share because we had a net loss and, therefore, the effect would have been anti-dilutive. There were no options excluded from the computation of diluted earnings per share for the three months ended June 30, 2009. For the three months ended June 30, 2008, options and warrants to purchase 370,000 shares of common stock were excluded from the computation of diluted earnings per share. There were no options

excluded from the computation of diluted earnings per share for the six months ended June 30, 2009. For the six months ended June 30, 2008, options and warrants to purchase 429,000 shares of common stock were excluded from the computation of diluted earnings per share.

NOTE 10. RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS

     In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations, (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non- controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008, which will be the Company’s fiscal year 2009. The adoption of SFAS 141(R) effective January 1, 2009 has had no effect on our financial position or results of operations as we have made no acquisitions during the six months ended June 30, 2009. However, the impact, if any, will depend on the nature and size of business combinations we consummate thereafter.

     In February 2008, the FASB issued Staff Position No. 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”), which granted a one-year deferral of the effective date of SFAS No. 157 as it applies to non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (e.g. those measured at fair value in a business combination and asset retirement obligations). Beginning January 1, 2009, we applied SFAS No. 157 to non-financial assets and liabilities. The adoption of SFAS No. 157 did not have a material impact on our financial position or results of operations.

     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 expanded 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 applied SFAS 161 beginning January 1, 2009. The adoption of SFAS No. 161 has not had an impact on our financial position or results of operations.

     In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, (“SFAS 162”), which becomes effective for the Company 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity With General Accepted Accounting Principles. This standard identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with generally accepted accounting principles. We do not anticipate that this pronouncement will have a material impact on our results of operations or financial position.

     In December 2008, the Securities and Exchange Commission published a Final Rule, Modernization of Oil and Gas Reporting. The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a)

report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The use of average prices will affect future impairment and depletion calculations.

     The new disclosure requirements are effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. A company may not apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. The Company has not yet determined the impact of this Final Rule, which will vary depending on changes in commodity prices, on its disclosures, financial position or results of operations.

     In April 2009, the FASB issued FASB Staff Position FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP 107-1”). FSP 107-1 amends FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This FSP also amends APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods. This FSP shall be effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. An entity may early adopt this FSP only if it also elects to early adopt FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, and FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments. This FSP does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this FSP requires comparative disclosures only for periods ending after initial adoption. We do not anticipate that this pronouncement will have a material impact on our results of operations or financial position.

     In April 2009, the FASB issued FASB Staff Position FAS 141-(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies (“FSP 141-(R)-1”). FSP 141-(R)-1 amends and clarifies FASB Statement No. 141 (revised 2007), Business Combinations to address application issues raised by preparers, auditors, and members of the legal profession on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This FSP shall be effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The impact, if any, will depend on the nature and terms of business combinations we consummate after the effective date.

     In May 2009, the FASB issued SFAS No. 165, “Subsequent Events ” (“SFAS 165”), which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In particular, this Statement sets forth (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. This Statement shall be effective for interim or annual financial periods ending after June 15, 2009, and shall be applied prospectively. We adopted SFAS 165 beginning June 30, 2009 and the adoption did not have a material impact on our financial position or results of operations. The date through which subsequent events have been evaluated is August 4, 2009, the date on which we filed our Form 10-Q with the Securities and Exchange Commission.

     In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification

TM and the Hierarchy of Generally Accepted Accounting Principles a replacement of FASB Statement No. 162 (“SFAS 168”) which establishes the FASB Accounting Standards Codification TM (Codification) as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This Statement shall be effective for financial statements issued for interim and annual periods ending after September 15, 2009. On the effective date of this Statement, all then-existing non-SEC accounting and reporting standards are superseded, except as noted within the SFAS 168. Concurrently, all nongrandfathered, non-SEC accounting literature not included in the Codification is deemed non-authoritative with some exceptions as noted within the literature. We do not anticipate that this pronouncement will have a material impact on our results of operations or financial position.

NOTE 11. COMMITMENTS AND CONTINGENCIES

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

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

     We received a Notice of Proposed Adjustment from the Internal Revenue Service, or the “Service” in May 2007 advising us of proposed adjustments to federal income tax of approximately $2.0 million for the years 2004 and 2005. Subsequent discussions with the Service placed the issues contested in a development status. In November 2007, the Service issued a letter on the matter giving us 30 days to agree or disagree with a final examination report. The final examination report reflected revisions of the previous proposed adjustments resulting in a reduced $1.1 million of additional income tax and interest charges. The decrease in proposed tax was the result of information supplied by us to the examiner as well as discussions of the applicable tax statutes and regulations. In December 2007, we filed a protest documenting our complete disagreement with the adjustments proposed on the final examination report and requested a conference with the appeals office of the Service. The examination office of the Service

filed a response to our protest in February 2008 with the appeals office. In the response the additional tax was further reduced by the examination office to $720,000. In June and November of 2008, our representatives met with the Service’s Appeals Officer to review specific issues related to the alternative minimum tax items in dispute. During these meetings we submitted supplements to our initial protest in further support of our position. On May 27, 2009 we received a written proposal from the Service under which we would not owe any additional taxes or interest for the years 2004 and 2005, but which would require us to reduce future alternative minimum tax net operating losses by approximately $18.6 million. We have accepted this offer and are awaiting final notification from the Service that this matter is closed. This reduction has no direct impact on our earnings, but could accelerate the timing of future tax payments.

     We also are 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 statues to which we are subject, nor have we been a party to any bankruptcy, receivership, reorganization, adjustment or similar proceedings.

     Effective January 1, 2005, we established a 401(k) Plan and Trust for eligible employees. For the three months ended June 30, 2009 and 2008, we made contributions to the 401(k) Plan and Trust of approximately $85,000 and $77,000, respectively. For the six months ended June 30, 2009 and 2008, we made contributions to the 401(k) Plan and Trust of approximately $172,000 and $152,000, respectively.

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 2008 Annual Report on Form 10-K, as well as the unaudited financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

OVERVIEW

Strategy

     2009 Priorities. Due to the current economic environment, we have identified four areas in which we will concentrate our efforts in 2009. These areas of concentration are dependent on market conditions and some could change as prices and events in 2009 develop. At present, our four top priorities for 2009 are:

	•		maximize liquidity and financial flexibility;
	•		generate “operating cash flow” in excess of our capital investment budget (“CAPEX”);
	•		invest $29.1 million in CAPEX spending; and
	•		focus on operated properties.

     As described in Note 4-“Oil and Natural Gas Properties”, we entered into a farmout agreement with Chesapeake Energy Corporation which will allow us to conserve cash and more importantly direct efforts in areas in which we believe have a greater rate of return for the Company. The majority of the remaining planned CAPEX spending for 2009 will be on our operated properties where we can control the timing and pace of this spending. If prices continue to deteriorate, we will be able to defer planned spending until prices increase and/or service costs decrease to support these projects. Under our current budget and with existing prices, we anticipate that all spending will be supported by operating cash flow generated by our expected production and by settlements of our derivative contracts. However, if we

determine that operating cash flow and derivative settlements will not support our spending, we will be able to alter our budget so that we retain our financial and operational flexibility in the existing adverse market environment.

     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. We also believe our expertise in utilizing this technology will create additional opportunities in our current projects as well as future opportunities in other resource plays. While we believe we can find oil and natural gas reserves more effectively using this technology, under the current economic environment, our capital resources can be better utilized elsewhere. We will continue to use this technology as natural gas prices and overall market conditions dictate.

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

     Acquire Long-Lived Properties with Enhancement Opportunities. Our acquisition strategy is focused on leveraging our geographical expertise in our core areas of operation and seeking assets located in and around these areas. We selectively evaluate acquisition opportunities and expect that they will continue to play a role in increasing our reserve base and future drilling inventory. When identifying target assets, we focus primarily on reserve quality and assets in new development plays with upside potential. Through this approach, we have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit properties without taking on significant integration risk. While we have not adopted any specific quantitative guidelines for the screening of prospective leasehold or producing property acquisitions, desirable attributes related to reserve life include a reserve to production ratio of greater than 15 years and stabilized exponential decline rates of less than 20% per year. We believe these types of properties provide us with a greater certainty in growing production, reserves and shareholder value through time.

     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;
	•		sources and availability of funds to conduct operations and complete acquisitions;
	•		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, such as the recent and dramatic downturn in the financial markets, can cause us to defer or deviate from our business strategy, including the amounts we have budgeted for our activities. See “-Trends and Outlook” below.

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.

     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.

     Overall, decreases in the average sales price of crude oil and natural gas is the most significant factor affecting operating performance. Our average price received for crude oil during the three months ended June 30, 2009 (the “Current Quarter”) was $55.57/Bbl versus $119.42/Bbl in the three months ended June 30, 2008 (the “Comparable Quarter”). Our average price received for natural gas in the Current Quarter was $2.78/Mcf versus $9.95/Mcf for the Comparable Quarter. Oil and natural gas sales revenue is down 65% when comparing the Current Quarter to the Comparable Quarter. The reduction in pricing accounts for approximately 87% of this reduction while volume decreases accounted for the remaining 13%. During the same time, operating costs and expenses were down 38%. A substantial portion of this reduction was due to a decrease in our depreciation, depletion and amortization costs. This was a direct result of our impairments which we incurred at year end 2008 and at the end of the prior quarter. For more information regarding prices received and operating results, you should refer to the selected operating data table under “-Results of Operations” on page 28.

     Our average price received for crude oil during the six months ended June 30, 2009 (the “Current Period”) was $45.79/Bbl versus $106.32/Bbl in the six months ended June 30, 2008 (the “Comparable Period”). Our average price received for natural gas in the Current Period was $3.21/Mcf versus $8.90/Mcf for the Comparable Period. Oil and natural gas sales revenue was down 62% when comparing the Current Period to the Comparable Period. The reduction in pricing accounts for approximately 92% of this reduction while volume decreases accounted for just 8%. During the same time, operating costs and expenses were down 25%, excluding the impact of the $30.4 million impairment write down we made in the quarter ended March 31, 2009. A substantial portion of this reduction was due to a decrease in our depreciation, depletion and amortization costs. This was a direct result of our impairments which we incurred at year end 2008 and at the end of the prior quarter. For more information regarding prices received and operating results, you should refer to the selected operating data table under “-Results of Operations” on page 28.

     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. Please see Note 4-“Oil and Natural Gas Properties” for a discussion on the impairment calculation.

     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.

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 six months ended June 30, 2009 and June 30, 2008.

		Three Months Ended June 30,								Six Months Ended June 30,
		2009				2008				2009				2008
		(in thousands, except per unit data)
Production Volumes:
Oil (Bbls)			248				237				500				484
Natural gas (Mcf)			2,196				2,790				4,725				5,452
BOE(1)			614				702				1,288				1,393
BOE per day			6.7				7.7				7.1				7.7
Sales Prices:
Oil (per Bbl)		$	55.57			$	119.42			$	45.79			$	106.32
Natural gas (per Mcf)		$	2.78			$	9.95			$	3.21			$	8.90
BOE price		$	32.37			$	79.86			$	29.58			$	71.80
Operating Revenues:
Oil		$	13,758			$	28,322			$	22,905			$	51,491
Natural gas			6,103				27,753				15,185				48,525
		$	19,861			$	56,075			$	38,090			$	100,016
Operating Expenses:
Lease operating expense		$	5,541			$	7,254			$	13,627			$	14,233
Production taxes			761				2,996				1,334				5,285
General and administrative			3,281				3,265				6,714				5,833
Depreciation, depletion and amortization			5,398				10,483				12,179				19,835
Impairment of oil and natural gas properties			—				—				30,426				—
		$	14,981			$	23,998			$	64,280			$	45,186
Operating income (loss)		$	4,880			$	32,077			$	(26,190	)		$	54,830