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 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):

     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

     At July 28, 2008, 41,549,746 shares of the Registrant’s Common Stock, $0.01 par value, were outstanding.

 

 

INDEX

				Page No.
PART I. — FINANCIAL INFORMATION
ITEM 1.		FINANCIAL STATEMENTS
		Reference is made to the succeeding pages for the following consolidated financial statements:
		- Consolidated Balance Sheets as of June 30, 2008 (unaudited) and December 31, 2007			1
		- Unaudited Consolidated Statements of Operations for the three months and six months ended June 30, 2008 and 2007			2
		- Unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2008 and 2007			3
		- Consolidated Statements of Stockholders’ Equity for year ended December 31, 2007 and as of June 30, 2008 (unaudited)			4
		- Notes to Consolidated Financial Statements			5
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			19
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			37
ITEM 4.		CONTROLS AND PROCEDURES			40
PART II. — OTHER INFORMATION
ITEM 1.		LEGAL PROCEEDINGS			40
ITEM 1A.		RISK FACTORS			42
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			42
ITEM 4.		SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			43
ITEM 6.		EXHIBITS			43
SIGNATURES
Certification of Principal Executive Officer pursuant to Section 302
Certification of Principal Financial Officer pursuant to Section 302
Certification of Principal Executive Officer pursuant to Section 906
Certification of Principal Financial Officer pursuant to Section 906

PART 1— FINANCIAL INFORMATION

ITEM 1.		FINANCIAL STATEMENTS

PARALLEL PETROLEUM CORPORATION
Consolidated Balance Sheets
($ in thousands)

		June 30,				December 31,
		2008				2007
		(unaudited)
Assets
Current assets:
Cash and cash equivalents		$	8,910			$	7,816
Accounts receivable:
Oil and natural gas sales			33,334				20,499
Joint interest owners and other, net of allowance for doubtful account of $50			1,905				2,460
Affiliates and joint ventures			6				3,970
			35,245				26,929
Other current assets			548				600
Deferred tax asset			21,461				10,293
Total current assets			66,164				45,638
Property and equipment, at cost:
Oil and natural gas properties, full cost method (including $109,761 and $86,402 not subject to depletion)			782,492				648,576
Other			3,033				2,877
			785,525				651,453
Less accumulated depreciation, depletion and amortization			(165,196	)			(145,482	)
Net property and equipment			620,329				505,971
Restricted cash			80				78
Investment in pipelines and gathering system ventures			328				8,638
Other assets, net of accumulated amortization of $1,711 and $1,425			3,886				2,768
		$	690,787			$	563,093
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities		$	62,917			$	47,848
Asset retirement obligations			877				598
Derivative obligations			62,962				30,424
Put obligations			302				—
Total current liabilities			127,058				78,870
Revolving credit facility			137,000				60,000
Senior notes (principal amount $150,000)			145,630				145,383
Asset retirement obligations			4,729				4,339
Derivative obligations			47,836				13,194
Put obligations			3,029				—
Deferred tax liability			19,916				26,045
Total long-term liabilities			358,140				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 41,545,114 and 41,252,644			415				412
Additional paid-in capital			198,726				196,457
Retained earnings			6,448				38,393
Total stockholders’ equity			205,589				235,262
		$	690,787			$	563,093

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

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

		Three Months Ended June 30,								Six Months Ended June 30,
		2008				2007				2008				2007
Oil and natural gas revenues:
Oil and natural gas sales		$	56,075			$	27,354			$	100,016			$	50,470
Cost and expenses:
Lease operating expense			7,254				5,576				14,233				9,975
Production taxes			2,996				1,194				5,285				2,248
Production tax refund			—				(1,209	)			—				(1,209	)
General and administrative			3,265				2,580				5,833				5,245
Depreciation, depletion and amortization			10,483				7,150				19,835				13,859
Total costs and expenses			23,998				15,291				45,186				30,118
Operating income			32,077				12,063				54,830				20,352
Other income (expense), net:
Loss on derivatives not classified as hedges			(71,609	)			(2,170	)			(93,495	)			(6,605	)
Interest and other income			32				56				65				108
Interest expense			(5,368	)			(4,312	)			(10,886	)			(8,020	)
Other expense			(1	)			21				(1	)			(15	)
Equity in gain (loss) of pipelines and gathering system ventures			165				(289	)			382				(594	)
Total other income (expense), net			(76,781	)			(6,694	)			(103,935	)			(15,126	)
Income (loss) before income taxes			(44,704	)			5,369				(49,105	)			5,226
Income tax benefit (expense), deferred			15,499				(1,905	)			17,160				(1,858	)
Net income (loss)		$	(29,205	)		$	3,464			$	(31,945	)		$	3,368
Net income (loss) per common share:
Basic		$	(0.70	)		$	0.09			$	(0.77	)		$	0.09
Diluted		$	(0.70	)		$	0.09			$	(0.77	)		$	0.09
Weighted average common shares outstanding:
Basic			41,446				37,786				41,359				37,667
Diluted			41,446				38,769				41,359				38,763

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

PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Cash Flows
Six Months Ended June 30, 2008 and 2007
(unaudited)
($ in thousands)

		2008				2007
Cash flows from operating activities:
Net income (loss)		$	(31,945	)		$	3,368
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			19,835				13,859
Gain on sale of automobiles			(4	)			—
Accretion of asset retirement obligation			187				164
Accretion of senior notes discount			247				—
Deferred income tax (benefit) expense			(17,160	)			1,858
Loss on derivatives not classified as hedges			93,495				6,605
Accretion of interest on put obligations			6				—
Common stock issued to directors			217				—
Stock option expense			227				59
Equity in (gain) loss of pipelines and gathering system ventures			(382	)			594
Bad debt expense			—				(30	)
Changes in assets and liabilities:
Other assets, net			(480	)			(88	)
Restricted cash			(2	)			273
Accounts receivable			(8,316	)			5,889
Other current assets			(99	)			293
Accounts payable and accrued liabilities			15,069				1,831
Net cash provided by operating activities			70,895				34,675
Cash flows from investing activities:
Additions to oil and natural gas properties			(124,727	)			(73,553	)
Proceeds from disposition of oil and natural gas properties			—				1,764
Additions to other property and equipment			(273	)			(214	)
Settlements on derivative instruments			(22,839	)			(5,862	)
Net investment in pipelines and gathering system ventures			(15	)			(2,848	)
Net cash used in investing activities			(147,854	)			(80,713	)
Cash flows from financing activities:
Borrowings from bank line of credit			77,000				46,000
Payments on bank line of credit			—				(1,500	)
Deferred financing cost			(270	)			(175	)
Proceeds from exercise of stock options and warrants			1,323				1,318
Net cash provided by financing activities			78,053				45,643
Net increase (decrease) in cash and cash equivalents			1,094				(395	)
Cash and cash equivalents at beginning of period			7,816				5,910
Cash and cash equivalents at end of period		$	8,910			$	5,515
Non-cash financing and investing activities:
Deferred purchase of derivative puts		$	3,325			$	—
Oil and natural gas properties asset retirement obligations		$	482			$	(385	)
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		$	9,901			$	8,474

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

PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Stockholders’ Equity
Year-Ended December 31, 2007 and Year-to-Date June 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			18				—				217				—				217
Warrants exercised			149				1				891				—				892
Fees associated with warrant exercise			—				—				(74	)			—				(74	)
Options exercised			125				2				503				—				505
Stock offering costs			—				—				368				—				368
Stock option expense			—				—				227				—				227
Tax benefit of stock option exercise in excess of compensation			—				—				137				—				137
Net loss			—				—				—				(31,945	)			(31,945	)
Balance
June 30, 2008			41,545			$	415			$	198,726			$	6,448			$	205,589

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

PARALLEL PETROLEUM CORPORATION
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 information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in this Quarterly Report on Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission. 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 six months ended June 30, 2008 and 2007, Parallel recognized compensation expense of approximately $227,000 and $59,000, respectively, with a tax benefit of approximately $77,000 and $20,000, respectively, associated with our stock option grants. During the second quarter of 2007, we revised our estimate of expected forfeitures of stock options granted to directors due to the resignation of a director and the subsequent forfeiture of 40,000 stock options held by him. As a result, we revised our estimate of the grant date fair value of shares expected to ultimately vest under our stock option plan by approximately $283,000. As a consequence, general and administrative expenses during the three months ended June 30, 2007 were reduced by approximately $154,000 which 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)
Third quarter 2008		$	559
Fourth quarter 2008			535
2009			1,534
2010			789
2011 and 2012			480
Total		$	3,897

     At June 30, 2008, options to purchase 310,045 shares of common stock were outstanding and vested. At that same date, options to purchase 476,250 shares were outstanding and unvested. During the six months ended June 30, 2008, options to purchase 355,000 shares were granted to the officers and employees, options to purchase 126,205 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 values of stock options granted prior to and remaining outstanding at June 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 June 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			(126	)		$	3.99
Surrendered			—			$	—
Outstanding June 30, 2008			787			$	13.84				9.1			$	4,949
Exercisable at June 30, 2008			310			$	6.45				4.4			$	4,242

		($ in thousands)
Average weighted grant date fair value of options issued and unvested, June 30, 2008		$	4,596
Average weighted grant date fair value of options issued and outstanding, June 30, 2008		$	5,750

     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 six months ended June 30, 2008 cash received from the exercise of stock options was approximately $505,000 with an associated $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 awarded was based on the last sales price of our common stock on the Nasdaq Global Market on the date of grant. For the six months ended June 30, 2008, compensation expense of approximately $57,000 was recognized with the 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)
Third quarter 2008		$	24
Fourth quarter 2008			24
2009			67
2010			29
2011			7
Total		$	151

     A summary of restricted stock activity as of June 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 June 30, 2008			7,500			$	20.91				2.9

     Stock Awards

     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, representing compensation expense in the amount of $160,000 for the six months ended June 30, 2008. The fair value of the common stock awarded 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.

     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 the units sold by us. Pursuant to the 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 148,637 warrants were exercised for net proceeds of approximately $818,000.

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 June 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 June 30, 2008, the principal amount outstanding under our revolving credit facility was $137.0 million, excluding $445,000 reserved for our letters of credit. Unamortized fees in the amount of $875,000 related to the prior Revolving Credit Agreement have been rolled into the current Revolving Credit Agreement, as amended, and will be amortized over the remaining term of five years.

     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

     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.

     Loans made to us under this revolving credit facility bear interest at the bank’s base rate or the “LIBOR” rate, at our election. Generally, the bank’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 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 June 30, 2008, our base rate, plus the applicable margin, was 5.0% on $137.0 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; 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 June 30, 2008 we were in compliance with all of the covenants in our Revolving Credit Agreement.

      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. The senior notes mature on August 1, 2014 and bear interest at 10.25% 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.

     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.

      Interest Accrued

     For the six months ended June 30, 2008, the aggregate interest accrued under our revolving credit facility and our senior notes was approximately $10.3 million. Bank fees and note discount amortization was approximately $621,000 and interest capitalized was approximately $44,000.

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 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 June 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 six month periods ended June 30, 2008 and 2007, overhead costs capitalized were approximately $842,000 and $725,000, 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.
	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 June 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)				June 30, 2008
Interest Swaps		$	—			$	(2,123	)		$	—			$	(2,123	)
Oil Swaps		$	—			$	(23,557	)		$	—			$	(23,557	)
Oil & Gas Collars		$	—			$	—			$	(88,018	)		$	(88,018	)
Oil Puts		$	—			$	—			$	2,900			$	2,900
		$	—			$	(25,680	)		$	(85,118	)		$	(110,798	)

     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 on our liabilities but also the credit standing of the counterparties involved.

     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, 2008								June 30, 2008
		Derivative				Derivative				Derivative				Derivative
		Collars				Puts				Collars				Puts
Beginning balance		$	(31,389	)		$	—			$	(15,852	)		$	—
Total losses			(60,743	)			(425	)			(77,489	)			(425	)
Settlements			4,114				—				5,323				—
Purchases			—				3,325				—				3,325
Transfers in and/or out of level 3			—				—				—				—
Ending balance		$	(88,018	)		$	2,900			$	(88,018	)		$	2,900
Change in unrealized losses included in earnings relating to derivatives still held as of June 30, 2008(1)		$	(56,629	)		$	(425	)		$	(72,166	)		$	(425	)

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 “mark to market” accounting as prescribed in SFAS 133. We view these contracts as protection against future interest rate volatility. As of June 30, 2008, the fair market value of these interest rate swaps was a liability of approximately $2.1 million.

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

		Notional				Weighted Average				Estimated
Period of Time		Amounts				Fixed Interest Rates				Fair Market Value
		($ in millions)								($ in thousands)
July 1, 2008 through December 31, 2008		$	100				4.86	%		$	(997	)
January 1, 2009 through December 31, 2009		$	50				5.06	%			(774	)
January 1, 2010 through October 31, 2010		$	50				5.15	%			(352	)
Total Fair Market Value										$	(2,123	)

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 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 contract. Future payments will be netted against any payments that the counterparty may owe to us based on the floating price. We have accrued a liability as of June 30, 2008 of $3.331 million for the purchase price of the puts, and we will pay a premium for these puts due to the deferral of the payments until the settlement dates. The premiums associated with these puts will be treated as interest expense and will have an effective interest rate between 4.3% and 5.7%.

     A summary of our put positions at June 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			$	505
January 1, 2010 through December 31, 2010			134,100			$	100.00				1,087
January 1, 2011 through December 31, 2011			146,000			$	100.00				1,308
Total Fair Market Value										$	2,900

      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 June 30, 2008 is as follows:

														Estimated
		Barrels of				NYMEX Oil Prices								Fair Market
Period of Time		Oil				Floor				Cap				Value
														($ in thousands)
July 1, 2008 through December 31, 2008			174,800			$	63.42			$	83.86			$	(9,941	)
January 1, 2009 through December 31, 2009			620,500			$	63.53			$	80.21				(36,970	)
January 1, 2010 through October 31, 2010			486,400			$	63.44			$	78.26				(28,180	)
		MMBtu of				WAHA Gas Prices
		Natural Gas				Floor				Cap
July 1, 2008 through December 31, 2008			1,840,000			$	7.38			$	9.28				(5,455	)
January 1, 2009 through December 31, 2009			3,285,000			$	7.06			$	9.93				(7,472	)
Total Fair Market Value														$	(88,018	)

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

     We have entered into oil swap contracts with BNP Paribas. A recap for the period of time, number of barrels and swap prices are as follows:

Estimated

Barrels of

NYMEX Oil

Fair Market

Period of Time

Oil

Swap Price

Value

($ in thousands

July 1, 2008 through December 31, 2008

220,800

$

33.37

$

(23,557

)

NOTE 7. NET INCOME (LOSS) PER COMMON SHARE

     Basic earnings per share (“EPS”) exclude any dilutive effects of option, warrants and convertible securities and is computed by dividing income (loss) 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 six months ended June 30, 2008 and 2007:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
		(in thousands, except per share data)
Basic EPS Computation:
Numerator-
Net income (loss)		$	(29,205	)		$	3,464			$	(31,945	)		$	3,368
Denominator-
Weighted average common shares outstanding			41,446				37,786				41,359				37,667
Basic EPS:
Net income (loss) per share		$	(0.70	)		$	0.09			$	(0.77	)		$	0.09
Diluted EPS Computation:
Numerator-
Net income (loss)		$	(29,205	)		$	3,464			$	(31,945	)		$	3,368
Denominator -
Weighted average common shares outstanding			41,446				37,786				41,359				37,667
Employee stock options			—				714				—				812
Warrants			—				269				—				284
Weighted average common shares for diluted earnings per share assuming conversion			41,446				38,769				41,359				38,763
Diluted EPS:
Net income (loss) per share		$	(0.70	)		$	0.09			$	(0.77	)		$	0.09

     For the three and six months ended June 30, 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 from continuing operations and therefore, the effect would have been antidilutive. Options and warrants to purchase approximately 370,000 and 429,000 shares of common stock were excluded from the computation of diluted earnings per share for the three and six months ended June 30, 2008, respectively, because their inclusion would have been antidilutive.

NOTE 8. ASSET RETIREMENT OBLIGATIONS

     The following table summarizes our asset retirement obligation transactions:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
		($ in thousands)
Beginning asset retirement obligation		$	5,802			$	5,034			$	4,937			$	5,063
Additions related to new properties			554				48				706				66
Revisions in estimated cash flows			(851	)			(55	)			(209	)			(167	)
Deletions related to property disposals			(3	)			(265	)			(15	)			(284	)
Accretion expense			104				80				187				164
Ending asset retirement obligation		$	5,606			$	4,842			$	5,606			$	4,842

NOTE 9. RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS

     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.

     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 June 30, 2008 we had total equity investments of $328,000 in West Fork Pipeline II, L.P. Our current investment percentage in this limited partnership is 23.25848%. For the three months ended June 30, 2008 we recorded a gain of $3,000, compared to a gain of $2,000 for the three month period ended June 30, 2007. For the six months ended June 30, 2008, we recorded a gain of $1,000, compared to a gain of $5,000 for the six month period ended June 30, 2007. West Fork Pipeline II, L.P. is currently acquiring the necessary easements and permits to begin transmission of natural gas.

     In June 2008, we acquired all of the assets of the Hagerman Gas Gathering System Joint Venture in connection with winding up and terminating the Joint Venture. At the time we acquired the assets, we had a net investment of approximately $8.7 million in the Joint Venture. For the three months ended June 30, 2008, we recorded an equity gain of $162,000, compared to a loss of $(291,000) for the three month period ended June 30, 2007. For the six months ended June 30, 2008, we recorded a gain of $381,000, compared to a loss of $(599,000) for the six months ended June 30, 2007. The increase in income from period to period is the result of greater gas volumes flowing through the gathering system in 2008, as compared to 2007.

     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.

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 (or is soon to be) 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. 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 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 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 June 30, 2008 and June 30, 2007 we made contributions to the 401(k) Plan and Trust of approximately $77,000 and $67,000, respectively. For the six months ended June 30, 2008 and June 30, 2007, we made contributions to the 401(k) Plan and Trust of approximately $152,000 and $134,000, 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 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 Advanced Technologies and Production Techniques. We believe that 3-D seismic surveys, horizontal drilling, fracture stimulation and other advanced technologies and production techniques are useful tools that help improve normal drilling operations and enhance our production and returns. We believe that our use of these technologies and production techniques in exploring for, developing and exploiting oil and natural gas properties can reduce drilling risks, lower finding costs, provide for more efficient production of oil and natural gas from our properties and increase the probability of locating and producing reserves that might not otherwise be discovered.

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

     Conduct Exploratory Activities. Although we do not emphasize exploratory drilling, we will selectively undertake exploratory projects that have known geological and reservoir characteristics 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.

     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 June 30, 2008 (the “Current Quarter”), the sale price we received for

our crude oil production averaged $119.42 per barrel, compared with $59.24 per barrel for the three months ended June 30, 2007 (the “Comparable Quarter”). The average sales price we received for natural gas for the Current Quarter was $9.95 per Mcf, compared with $6.79 per Mcf for the Comparable Quarter. For information regarding prices received, refer to the selected operating data table under “-Results of Operations” on page 22.

     For the six months ended June 30, 2008 (the “Current Period”), the sale price we received for our crude oil production averaged $106.32 per barrel, compared with $55.56 per barrel for the six months ended June 30, 2007 (the “Comparable Period”). The average sales price we received for natural gas for the Current Period was $8.90 per Mcf, compared with $6.34 per Mcf for the Comparable Period. For information regarding prices received, refer to the selected operating data table under “-Results of Operations” on page 22.

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

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

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, 2008 and June 30, 2007.

		Three Months Ended								Six Months Ended
		6/30/2008				6/30/2007				6/30/2008				6/30/2007
		(in thousands, except per unit data)
Production Volumes:
Oil (Bbls)			237				270				484				543
Natural gas (Mcf)			2,790				1,679				5,452				3,200
BOE(1)			702				550				1,393				1,076
BOE per day			7.7				6.0				7.7				5.9
Sales Prices:
Oil (per Bbl)		$	119.42			$	59.24			$	106.32			$	55.56
Natural gas (per Mcf)		$	9.95			$	6.79			$	8.90			$	6.34
BOE price		$	79.86			$	49.81			$	71.80			$	46.89
Operating Revenues
Oil		$	28,322			$	15,956			$	51,491			$	30,167
Natural gas			27,753				11,398				48,525				20,303
		$	56,075			$	27,354			$	100,016			$	50,470
Operating Expenses:
Lease operating expense		$	7,254			$	5,576			$	14,233			$	9,975
Production taxes			2,996				1,194				5,285				2,248
Production tax refund			—				(1,209	)			—				(1,209	)
General and administrative			3,265				2,580				5,833				5,245
Depreciation, depletion and amortization			10,483				7,150				19,835				13,859
		$	23,998			$	15,291			$	45,186			$	30,118
Operating income		$	32,077			$	12,063			$	54,830			$	20,352

RESULTS OF OPERATIONS

For the Three Months Ended June 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.

		Revenues								Production
		2008				2007				2008				2007
Oil			51	%			58	%			34	%			49	%
Natural gas			49	%			42	%			66	%			51	%
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 June 30,								Increase				% Increase
		2008				2007				(Decrease)				(Decrease)
		(in thousands except per unit data)
Production Volumes
Oil (Bbls)			237				270				(33	)			(12	)%
Natural gas (Mcf)			2,790				1,679				1,111				66	%
BOE			702				550				152				28	%
BOE/Day			7.7				6.0				1.7				28	%
Sales Price
Oil (per Bbl)		$	119.42			$	59.24			$	60.18				102	%
Natural gas (per Mcf)		$	9.95			$	6.79			$	3.16				47	%
BOE price		$	79.86			$	49.81			$	30.05				60	%
Operating Revenues
Oil		$	28,322			$	15,956			$	12,366				78	%
Natural gas			27,753				11,398				16,355				143	%
Total		$	56,075			$	27,354			$	28,721				105	%

Oil revenues

     Average wellhead realized crude oil prices increased $60.18 per Bbl, or 102%, to $119.42 per Bbl in the Current Quarter, over the Comparable Quarter. This price increase resulted in increased revenues by approximately $14.3 million for the Current Quarter, as compared to the Comparable Quarter. Oil production decreased 12%, which was attributable to natural production declines of approximately 33,000 Bbls. This decrease in production is largely due to natural declines in the Permian Basin area. The decrease in oil production resulted in decreased revenue of approximately $1.9 million for the Current Quarter.

Natural gas revenues

     Average realized wellhead natural gas prices increased $3.16 per Mcf, or 47%, to $9.95 per Mcf in the Current Quarter, over the Comparable Quarter. This price increase accounted for an increase in revenue of approximately $8.8 million. Natural gas production increased 66% in the Current Quarter primarily due to new wells in the New Mexico Wolf Camp and Barnett Shale areas where volumes were up approximately 444,000 Mcf and 743,000 Mcf, respectively, over the Comparable Quarter. The overall increase in natural gas volumes increased revenue approximately $7.6 million for the Current Quarter.

Cost and Expenses

		Three months ended June 30,								Increase				% Increase
		2008				2007				(Decrease)				(Decrease)
						($ in thousands)
Lease operating expense		$	7,254			$	5,576			$	1,678				30	%
Production taxes			2,996				1,194				1,802				151	%
Production tax refund			—				(1,209	)			1,209				(100	)%
General and administrative			3,265				2,580				685				27	%
Depreciation, depletion and amortization			10,483				7,150				3,333				47	%
Total		$	23,998			$	15,291			$	8,707				57	%