UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2008

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

For the transition period from                      to                     

Concho Resources Inc.

(Exact name of registrant as specified in its charter)

Delaware		76-0818600
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
550 West Texas Avenue, Suite 1300
Midland, Texas		79701
(Address of principal executive offices)		(Zip code)

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

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

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

     Number of shares of the registrant’s common stock outstanding at August 12, 2008: 84,432,912 shares.

 

 

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item 1. CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			22
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			39
Item 4. CONTROLS AND PROCEDURES			41
PART II — OTHER INFORMATION
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			41
Item 4. Submission of Matters to a Vote of Security Holders
Item 6. Exhibits			42
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

PART I – FINANCIAL INFORMATION

Item 1. CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Consolidated balance sheets as of June 30, 2008 and December 31, 2007			1
Consolidated statements of operations for the three and six months ended June 30, 2008 and 2007			2
Consolidated statement of stockholders’ equity for the six months ended June 30, 2008			3
Consolidated statements of cash flows for the six months ended June 30, 2008 and 2007			4
Condensed notes to consolidated financial statements			5

Concho Resources Inc. and subsidiaries

		June 30,				December 31,
(in thousands, except share and per share data)		2008				2007
Assets
Current assets:
Cash and cash equivalents		$	31,716			$	30,424
Accounts receivable:
Oil and gas, net of allowance for doubtful accounts			55,270				36,735
Joint operations and other			10,903				21,183
Assets held for sale			—				256
Derivative instruments			—				1,866
Deferred income taxes			44,750				13,502
Prepaid insurance and other			3,224				4,017
Total current assets			145,863				107,983
Property and equipment, at cost:
Oil and gas properties, successful efforts method			1,675,163				1,555,018
Accumulated depletion and depreciation			(209,688	)			(167,109	)
Total oil and gas properties, net			1,465,475				1,387,909
Other property and equipment, net			10,046				7,085
Total property and equipment, net			1,475,521				1,394,994
Deferred loan costs, net			3,800				3,426
Inventory			8,702				1,459
Other assets			347				367
Total assets		$	1,634,233			$	1,508,229
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable:
Trade		$	5,509			$	14,222
Related parties			623				2,119
Other current liabilities:
Bank overdrafts			8,896				5,651
Revenue payable			22,212				14,494
Accrued drilling costs			34,955				39,276
Accrued interest			496				1,590
Other accrued liabilities			18,291				11,935
Derivative instruments			114,504				36,414
Income taxes payable			—				29
Current portion of long-term debt			2,500				2,000
Current asset retirement obligations			765				912
Total current liabilities			208,751				128,642
Long-term debt			298,453				325,404
Noncurrent derivative instruments			44,824				10,517
Deferred income taxes			288,098				259,070
Asset retirement obligations and other long-term liabilities			10,148				9,198
Commitments and contingencies (Note K)
Stockholders’ equity:
Preferred stock, $0.001 par value; 10,000,000 shares authorized; and zero shares issued and outstanding at June 30, 2008 and December 31, 2007			—				—
Common stock, $0.001 par value; 300,000,000 authorized; 76,140,269 and 75,832,310 shares issued at June 30, 2008 and December 31, 2007, respectively			76				76
Additional paid-in capital			759,928				752,380
Notes receivable from employees			—				(330	)
Retained earnings			45,412				37,467
Accumulated other comprehensive income (loss)			(21,332	)			(14,195	)
Treasury stock, at cost; 3,142 and zero shares of common stock at June 30, 2008 and December 31, 2007, respectively			(125	)			—
Total stockholders’ equity			783,959				775,398
Total liabilities and stockholders’ equity		$	1,634,233			$	1,508,229

The accompanying notes are an integral part of these consolidated financial statements.

Concho Resources Inc. and subsidiaries

		Three months ended								Six months ended
		June 30,								June 30,
(in thousands, except per share amounts)		2008				2007				2008				2007
Operating revenues:
Oil sales		$	95,408			$	43,096			$	171,226			$	82,467
Natural gas sales			41,975				23,007				72,868				43,982
Total operating revenues			137,383				66,103				244,094				126,449
Operating costs and expenses:
Oil and gas production			9,949				6,950				17,766				14,209
Oil and gas production taxes			12,030				5,256				21,108				9,943
Exploration and abandonments			723				5,864				3,464				6,305
Depreciation and depletion			22,010				17,609				43,294				37,033
Accretion of discount on asset retirement obligations			148				115				301				228
Impairments of proved oil and gas properties			53				2,085				69				3,198
Contract drilling fees — stacked rigs			—				915				—				4,269
General and administrative (including non-cash stock-based compensation of $1,730 and $1,128 for the three months ended June 30, 2008 and 2007, respectively, and $3,029 and $1,954 for the six months ended June 30, 2008 and 2007, respectively)			8,586				7,629				16,266				11,921
Bad debt expense			1,799				—				1,799				—
Ineffective portion of cash flow hedges			(356	)			(99	)			(920	)			1,156
Loss on derivatives not designated as hedges			102,456				—				119,634				—
Total operating costs and expenses			157,398				46,324				222,781				88,262
Income (loss) from operations			(20,015	)			19,779				21,313				38,187
Other income (expense):
Interest expense			(3,885	)			(10,074	)			(9,500	)			(20,749	)
Other, net			311				208				1,331				473
Total other expense			(3,574	)			(9,866	)			(8,169	)			(20,276	)
Income (loss) before income taxes			(23,589	)			9,913				13,144				17,911
Income tax benefit (expense)			9,169				(3,988	)			(5,199	)			(7,363	)
Net income (loss)			(14,420	)			5,925				7,945				10,548
Preferred stock dividends			—				(11	)			—				(45	)
Net income (loss) applicable to common shareholders		$	(14,420	)		$	5,914			$	7,945			$	10,503
Basic earnings (loss) per share:
Net income (loss) per share		$	(0.19	)		$	0.10			$	0.11			$	0.19
Weighted average shares used in basic earnings (loss) per share			75,665				57,747				75,569				56,369
Diluted earnings (loss) per share:
Net income (loss) per share		$	(0.19	)		$	0.10			$	0.10			$	0.18
Weighted average shares used in diluted earnings (loss) per share			75,665				59,625				77,034				59,260

The accompanying notes are an integral part of these consolidated financial statements.

Concho Resources Inc. and subsidiaries

														Notes								Accumulated
										Additional				receivable from								other												Total
		Common stock								paid-in				officers and				Retained				comprehensive				Treasury stock								stockholders’
(in thousands)		Shares				Amount				capital				employees				earnings				income (loss)				Shares				Amount				equity
BALANCE AT DECEMBER 31, 2007			75,832			$	76			$	752,380			$	(330	)		$	37,467			$	(14,195	)			—			$	—			$	775,398
Comprehensive income
Net income			—				—				—				—				7,945				—				—				—				7,945
Deferred hedge losses, net of tax benefit of $12,705			—				—				—				—				—				(19,805	)			—				—				(19,805	)
Net settlement losses included in earnings, net of tax benefit of $8,127			—				—				—				—				—				12,668				—				—				12,668
Total comprehensive income																																			808
Stock options exercised			263				—				2,373				—				—				—				—				—				2,373
Restricted stock issued as stock-based compensation			81				—				862				—				—				—				—				—				862
Cancellation of restricted stock			(36	)			—				—				—				—				—				—				—				—
Stock-based compensation for stock options			—				—				2,167				—				—				—				—				—				2,167
Tax benefits related to stock-based compensation			—				—				2,146				—				—				—				—				—				2,146
Proceeds from notes receivable — officers and employees			—				—				—				333				—				—				—				—				333
Accrued interest — employee notes			—				—				—				(3	)			—				—				—				—				(3	)
Purchase of treasury stock			—				—				—				—				—				—				3				(125	)			(125	)
BALANCE AT JUNE 30, 2008			76,140			$	76			$	759,928			$	—			$	45,412			$	(21,332	)			3			$	(125	)		$	783,959

The accompanying notes are an integral part of these consolidated financial statements.

Concho Resources Inc. and subsidiaries

		Six months ended
		June 30,
(in thousands)		2008				2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	7,945			$	10,548
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion			43,294				37,033
Impairments of proved oil and gas properties			69				3,198
Accretion of discount on asset retirement obligations			301				228
Exploration expense, including dry holes			1,147				5,665
Non-cash compensation expense			3,029				1,954
Bad debt expense			1,799				—
Gas imbalances			(137	)			54
Deferred rent liability			22				41
Deferred income taxes			4,504				7,399
Interest accrued on employee notes			(3	)			(240	)
Amortization of deferred loan costs			627				1,889
Amortization of discount on long-term debt			49				40
Gain on sale of property and equipment			(777	)			—
Ineffective portion of cash flow hedges			(920	)			1,156
Loss on derivatives not designated as hedges			119,634				—
Dedesignated cash flow hedges reclassified from AOCI			222				—
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable			(12,003	)			10,640
Prepaid insurance and other			793				3,985
Inventory			(7,243	)			(5,000	)
Excess tax benefit from stock-based compensation			(2,146	)			—
Accounts payable			(10,209	)			(14,902	)
Revenue payable			7,718				(404	)
Accrued liabilities			6,356				(519	)
Accrued interest			(1,094	)			829
Income taxes payable			(29	)			—
Net cash provided by operating activities			162,948				63,594
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and gas properties			(122,757	)			(69,889	)
Acquisition of oil and gas properties and other assets			—				(256	)
Additions to other property and equipment			(4,017	)			(1,114	)
Proceeds from the sale of oil and gas properties			1,034				652
Settlements paid on derivatives not designated as hedges			(16,387	)			—
Net cash used in investing activities			(142,127	)			(70,607	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt			13,000				266,100
Payments of long-term debt			(39,500	)			(257,600	)
Exercise of incentive plan stock options			2,373				—
Excess tax benefit from stock-based compensation			2,146				—
Payments of preferred stock dividends			—				(132	)
Proceeds from repayment of officer and employee notes			333				10,482
Payments for loan origination costs			(1,001	)			(2,572	)
Purchase of treasury stock			(125	)			—
Bank overdrafts			3,245				—
Net cash provided by (used in) financing activities			(19,529	)			16,278
Net increase in cash and cash equivalents			1,292				9,265
BEGINNING CASH AND CASH EQUIVALENTS			30,424				1,122
ENDING CASH AND CASH EQUIVALENTS		$	31,716			$	10,387
SUPPLEMENTAL CASH FLOWS:
Cash paid for interest and fees, net of $840 and $1,336 capitalized interest		$	9,918			$	18,891
Cash paid for income taxes		$	650			$	1,800
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Issuance of common stock in acquisition of oil and gas properties and other assets		$	—			$	650

The accompanying notes are an integral part of these consolidated financial statements.

Concho Resources Inc. and subsidiaries

Note A. Organization and nature of operations

     Concho Resources Inc. (“Resources”) is a Delaware corporation formed by Concho Equity Holdings Corp. (“CEHC”) on February 22, 2006, for purposes of effecting the combination of CEHC, Chase Oil Corporation, Caza Energy LLC (“Caza”) and certain other parties thereto (collectively with Chase Oil Corporation and Caza, the “Chase Group”). Pursuant to the Combination Agreement dated February 24, 2006, Resources acquired working interests in oil and natural gas properties in Southeast New Mexico from the Chase Group (“Chase Group Properties”) and issued shares of its common stock to certain stockholders of CEHC in exchange for their capital stock of CEHC. CEHC is a Delaware corporation formed on April 21, 2004 by certain members of the Company’s management team and private equity investors. CEHC commenced substantial oil and gas operations in December 2004 upon its acquisition of certain oil and gas properties located in Southeast New Mexico and West Texas. The combination transaction described above (the “Combination”) was accounted for as an acquisition by CEHC of the Chase Group Properties and a simultaneous reorganization of Resources such that CEHC is now a wholly owned subsidiary of Resources. Prior to the Combination, Resources had no assets, operations or net equity. Upon the closing of the Combination, the executive officers of CEHC became the executive officers of Resources. Resources and its wholly owned subsidiaries are collectively referred to herein as the “Company.”

     CEHC’s shareholders received 23,767,691 shares of common stock of Resources in exchange for their preferred and common shares of CEHC, excluding eighteen holders owning an aggregate of 254,621 shares of CEHC 6% Series A Preferred Stock and 127,313 shares of CEHC common stock, as discussed in Note G — Stockholders’ equity and stock issued subject to limited recourse notes. In addition, the Chase Group transferred the Chase Group Properties to Resources in exchange for cash in the aggregate amount of approximately $409 million and 34,794,638 shares of Resources common stock. In connection with the Company’s initial public offering and secondary public offering (both described below), the Chase Group sold a total of 18,638,014 shares of common stock thereby reducing its ownership interest. As of June 30, 2008 and December 31, 2007, the Chase Group owned approximately 12 percent and 21 percent, respectively, of the total outstanding common stock of the Company.

     The Company’s principal business is the acquisition, development, exploitation and exploration of oil and gas properties in the Permian Basin region of Southeast New Mexico and West Texas.

     Initial public offering. On August 7, 2007, the Company completed an initial public offering (the “IPO”) of its common stock. The Company sold 13,332,851 shares of its common stock in the IPO and certain shareholders, including its executive officers and members of the Chase Group, sold 7,554,256 shares of Resources common stock, in each case, at $11.50 per share. After deducting underwriting discounts of approximately $9.6 million and offering expenses of approximately $4.5 million, the Company received net proceeds of approximately $139.2 million. In conjunction with the IPO, the underwriters were granted an option to purchase 3,133,066 additional shares of Resources common stock. The underwriters fully exercised this option and purchased the additional shares on August 9, 2007. After deducting underwriting discounts of approximately $2.2 million, the Company received net proceeds of approximately $33.8 million. The aggregate net proceeds of approximately $173.0 million received by the Company at closing on August 7, 2007 and August 9, 2007 were utilized in equal amounts to repay a portion of its term loan facility on August 9, 2007, and to prepay a portion of its revolving credit facility on August 20, 2007. See further discussion in Note J — Long-term debt.

     Secondary public offering. On December 19, 2007, the Company completed a secondary public offering of 11,845,000 shares of its common stock, which were sold by certain of its stockholders, including members of the Chase group. The Chase Group sold 10,194,732 shares in the aggregate and certain other stockholders of the Company sold 1,650,268 shares in the aggregate, including one of the Company’s executive officers who sold 45,000 shares. Chase Oil Corporation granted the underwriters an option to purchase up to 1,776,615 additional shares to cover over-allotments, which was fully exercised on December 19, 2007. The Company did not receive any proceeds from the sale of its common stock in this secondary offering.

Note B. Summary of significant accounting policies

     Principles of consolidation. The consolidated financial statements of Resources include the accounts of Resources and its wholly owned subsidiaries, including CEHC. All material intercompany balances and transactions have been eliminated.

     Interim financial statements. The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2007 is derived from audited financial statements. In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly the Company’s financial position at June 30, 2008, its income for the three and six months ended June 30,

2008 and 2007 and its cash flows for the six months ended June 30, 2008 and 2007. All such adjustments are of a normal recurring nature. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results.

     Certain disclosures have been condensed or omitted from these financial statements. Accordingly, these financial statements should be read with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.

     Oil and gas sales and imbalances. Oil and gas revenues are recorded at the time of delivery of such products to pipelines for the account of the purchaser or at the time of physical transfer of such products to the purchaser. The Company follows the sales method of accounting for oil and gas sales, recognizing revenues based on the Company’s share of actual proceeds from the oil and gas sold to purchasers. Oil and gas imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage. Imbalances are tracked by well, but the Company does not record any receivable to or payable from the other owners unless the imbalance has reached a level whereby it exceeds the remaining reserves in the respective well. If reserves are insufficient to offset the imbalance and the Company is in an overtake position, a liability is recorded for the amount of shortfall in reserves valued at a contract price or the market price in effect at the time the imbalance is generated. If the Company is in an undertake position, a receivable is recorded for an amount that is reasonably expected to be received, not to exceed the current market value of such imbalance.

     At June 30, 2008, the Company had a gas imbalance liability, included in Asset retirement obligations and other long-term liabilities in the accompanying consolidated balance sheet of approximately $464,000 related to the Company’s overtake position of 83,714 Mcf on certain wells and a gas imbalance receivable, included in Other assets in the accompanying consolidated balance sheet of approximately $347,000 related to the Company’s undertake position of 77,171 Mcf on certain wells.

     Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. During the three and six months ended June 30, 2008, the Company did not retire any treasury stock.

     General and administrative expense. The Company receives fees for its operation of jointly owned oil and gas properties and records such reimbursements as reductions of General and administrative expense. Such fees totaled approximately $265,000 and $221,000 for the three months ended June 30, 2008 and 2007, respectively, and $504,000 and $630,000 for the six months ended June 30, 2008 and 2007, respectively.

Note C. Exploratory well costs

     Costs of drilling exploratory wells are capitalized, pending management’s determination of whether the wells have found proved reserves. If proved reserves are found, the costs remain capitalized. If proved reserves are not found, the capitalized costs of drilling the well are charged to expense. Management makes this determination as soon as possible after completion of drilling considering the guidance provided in Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and FASB Staff Position (“FSP”) No. 19-1, “Accounting for Suspended Well Costs.”

     The following table provides an aging, as of June 30, 2008 and December 31, 2007, of capitalized exploratory well costs based on the date drilling was completed:

		June 30,				December 31,
(in thousands)		2008				2007
Wells in progress		$	1,038			$	4,199
Capitalized exploratory well costs that have been capitalized for a period of one year or less			15,240				16,857
Capitalized exploratory well costs that have been capitalized for a period greater than one year			—				—
Total exploratory well costs		$	16,278			$	21,056

     As of June 30, 2008, the capitalized exploratory well costs of approximately $16.3 million had been deferred for a period of one year or less and were related primarily to the Company’s New Mexico shelf properties and emerging resource plays.

     As of December 31, 2007, the capitalized exploratory well costs of approximately $21.1 million had been deferred for a period of one year or less and were related primarily to the Company’s New Mexico shelf and New Mexico basin properties.

Note D. Fair value measurements

     The Company adopted SFAS No. 157, “Fair Value Measurements,” (“SFAS No. 157”) effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. 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. 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. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, investments and interest rate swaps. Our valuation models are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. We utilize our counterparties’ valuations to assess the reasonableness of our prices and valuation techniques.
	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). Level 3 instruments primarily include derivative instruments, such as basis swaps, commodity price collars and floors, as well as investments. 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. Although we utilize our counterparties’ valuations to assess the reasonableness of our prices and valuation techniques, we do not have sufficient corroborating market evidence 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. The Company’s 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 the Company’s financial instruments by SFAS No. 157 pricing levels as of June 30, 2008:

		Fair value measurements using
		Quoted				Significant								Total
		prices				other				Significant				carrying value
		in active				observable				unobservable				at
		markets				inputs				inputs				June 30,
(in thousands)		(Level 1)				(Level 2)				(Level 3)				2008
Oil and natural gas derivative swap contracts		$	—			$	(143,402	)		$	—			$	(143,402	)
Oil and natural gas derivative collar contracts			—				—				(15,926	)			(15,926	)
Total financial liabilities		$	—			$	(143,402	)		$	(15,926	)		$	(159,328	)

     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):

(in thousands)		Derivatives
Balance as of January 1, 2008		$	1,866
Total gains or (losses), realized or unrealized			(18,214	)
Purchases, issuances, and settlements			422
Balance as of June 30, 2008		$	(15,926	)
Total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets and/or liabilities still held at the reporting date		$	(17,792	)

Note E. New accounting pronouncements

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of FASB Statement No. 115,” which became effective in 2008. SFAS No. 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. The Company adopted this statement January 1, 2008, and the Company did not elect the fair value option for any of its eligible financial instruments or other items. As such, the adoption had no impact on the Company’s consolidated financial statements.

     In April 2007, the FASB issued FASB Staff Position FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FIN No. 39-1”). FIN No. 39-1 clarifies that a reporting entity that is party to a master netting arrangement can offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement. FIN No. 39-1 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company adopted FIN No. 39-1 effective January 1, 2008, and it has had no material impact on the Company’s consolidated financial statements.

     In June 2007, the FASB ratified a consensus opinion reached by the Emerging Issues Task Force (“EITF”) on EITF Issue 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards.” EITF Issue 06-11 requires an employer to recognize tax benefits realized from dividend or dividend equivalents paid to employees for certain share-based payment awards as an increase to additional paid-in capital and include such amounts in the pool of excess tax benefits available to absorb future tax deficiencies on share-based payment awards. If an entity’s estimate of forfeitures increases (or actual forfeitures exceed the entity’s estimates), or if an award is no longer expected to vest, entities should reclassify the dividends or dividend equivalents paid on that

award from retained earnings to compensation cost. However, the tax benefits from dividends that are reclassified from additional paid-in capital to the income statement are limited to the entity’s pool of excess tax benefits available to absorb tax deficiencies on the date of reclassification. The adoption of EITF Issue 06-11 has not had a significant effect on the Company’s financial statements since it historically has accounted for the income tax benefits of dividends paid for share-based payment awards in the manner described in the consensus.

     In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141(R)”), which replaces FASB Statement No. 141. SFAS No. 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 No. 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 impact, if any, will depend on the nature and size of business combinations the Company consummates 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 No. 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS No. 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 No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008, which will be the Company’s fiscal year 2009. Based upon the Company’s June 30, 2008 consolidated balance sheet, the statement would have no impact.

     In December 2007, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 110, “Share-Based Payment” (“SAB No. 110”). SAB No. 110 amends SAB No. 107, “Share-Based Payment,” and allows for the continued use, under certain circumstances, of the simplified method in developing an estimate of the expected term on stock options accounted for under SFAS No. 123R, “Share-Based Payment (revised 2004).” SAB No. 110 is effective for stock options granted after December 31, 2007. The Company continued to use the simplified method in developing an estimate of the expected term on stock options granted in the first and second quarters of 2008. The Company does not have sufficient historical exercise data to provide a reasonable basis upon which to estimate expected term due to the limited period of time its shares of common stock have been publicly traded.

     In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”), which amends and expands the disclosure requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), to provide an enhanced understanding of an entity’s use of derivative instruments, how they are accounted for under SFAS No. 133 and their effect on the entity’s financial position, financial performance and cash flows. The provisions of SFAS No. 161 are effective as of January 1, 2009. The Company is currently evaluating the impact on its consolidated financial statements of adopting SFAS No. 161.

Note F. Asset retirement obligations

     The Company’s asset retirement obligations represent the estimated present value of the estimated cash flows the Company will incur to plug, abandon and remediate its producing properties at the end of their production lives, in accordance with applicable state laws. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.

     The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of SFAS No. 143 during the six months ended June 30, 2008 and 2007:

		Six months ended
		June 30,
(in thousands)		2008				2007
Asset retirement obligations, beginning of period		$	9,418			$	8,700
Liability incurred upon acquiring and drilling wells			309				131
Accretion expense			301				228
Revisions to estimated cash flows			328				(1,393	)
Asset retirement obligations, end of period		$	10,356			$	7,666

Note G. Stockholders’ equity and stock issued subject to limited recourse notes

     Equity commitments. Pursuant to a stock purchase agreement (the “Stock Purchase Agreement”) entered into on August 13, 2004, the Company obtained private equity commitments totaling $202.5 million, comprised of equity commitments from fourteen private investors (the “Private Investors”) of approximately $188.9 million and equity commitments from the five original officers (the “Officers”) of the Company in the aggregate amount of $13.6 million. The original commitments were subject to call by a vote of the board of directors over a four year period beginning August 13, 2004 (the “Take-Down Period”), with the first date on which capital was called being August 13, 2004. Subsequent calls were made on November 11, 2004, June 22, 2005, December 7, 2005 and February 10, 2006. The percentage of total commitments called per capital call date was approximately 15.0 percent, 23.3 percent, 10.0 percent, 15.0 percent and 22.0 percent, respectively. In conjunction with the exchange of CEHC common stock for Resources common stock as of the date of the Combination, the remaining 14.7 percent of these private equity commitments was terminated.

     In addition to this arrangement between the Private Investors and the Officers, certain employees and executive officers of the Company entered into separate subscription agreements with the Company. The officers’ and employees’ equity purchases were paid in a combination of cash and the issuance of notes payable to the Company with recourse only to any equity security of the Company held by the respective officer or employee (the “Purchase Notes”). Based on guidance contained in SFAS No. 123R, the agreements to sell stock to the Officers and certain employees subject to Purchase Notes are accounted for as the issuance of options (“Bundled Capital Options” for the Officers and “Capital Options” for certain employees) on the dates that the various subscription agreements were signed and the purchase commitments were made.

     Capital calls. From inception of the Company through February 23, 2006, the Private Investors purchased 16,113,170 Preferred Units for $161.1 million in cash. The Officers had purchased 2,240,083 CEHC common shares and 938,303 Preferred Units for $3.6 million in cash and Purchase Notes totaling $8.0 million. Certain employees purchased 425,221 Preferred Units for $1.0 million in cash and Purchase Notes totaling $3.8 million.

     6% Series A preferred stock. Preferred stock dividends were generally paid on the anniversary of date of issue. There were no dividend payments made during the three and six months ended June 30, 2008, because there was no outstanding preferred stock. Preferred stock dividends of approximately $98,000 and $132,000 were paid during the three and six months ended June 30, 2007, respectively. As discussed in Note A — Organization and nature of operations and below, the majority of the CEHC preferred stock was converted into Resources common stock on the Combination date. Final dividend payments on converted CEHC 6% Series A Preferred Stock were made in March 2006.

     Dividend payments continued to be made to the eighteen employee shareholders that did not convert their shares of CEHC preferred stock to Resources common stock through April 16, 2007. On April 16, 2007, these CEHC preferred shares were exchanged for 190,972 shares of the Company’s common stock. These shares are reported as if converted on the Combination date. Final dividend payments on this final portion of converted CEHC 6% Series A Preferred Stock were made on April 16, 2007.

     Purchase Notes. On April 23, 2007, the Company’s executive officers repaid their Purchase Notes in full, including principal of $9,426,000 and accrued interest of $1,037,000. The agreements to sell stock to the executive officers of the Company subject to Purchase Notes were accounted for as the issuance of options. As such, the repayment of the executive officer Purchase Notes represents the full exercise of the options on the Bundled Capital Options (as defined below) the Officers held as well as the Capital Options (as defined below) of one certain employee who is currently an executive officer.

     At June 30, 2008, all Purchase Notes from all employees had been paid in full. As such, the repayment of the Purchase Notes represents the full exercise of the options on the Capital Options the certain employees held.

     The following table summarizes the Capital Options activity for the six months ended June 30, 2008:

		Number of				Weighted
		Capital				average
		Options				exercise price
Six months ended June 30, 2008
Outstanding at beginning of period			38,385			$	8.34
$10 Capital Options exercised			(38,385	)		$	8.34
Outstanding at end of period			—			$	—
Vested outstanding at end of period			—			$	—

     Conversion of CEHC 6% Series A Preferred Stock and CEHC common stock. On February 27, 2006, concurrent with the closing of the Combination described in Note A — Organization and nature of operations, the majority of the shares of CEHC preferred stock and shares of CEHC common stock outstanding were converted to shares of Resources common stock, as described below.

     Eighteen employee shareholders owning an aggregate of 254,621 shares of CEHC preferred stock and 127,313 shares of CEHC common stock did not convert their shares to Resources common stock at the date of the Combination. On April 16, 2007, these remaining shares of CEHC were exchanged for 318,285 shares of the Company’s common stock. These shares are reported as if converted on the Combination date. In addition, CEHC made a final dividend payment to these eighteen employee shareholders on their CEHC preferred stock in the aggregate amount of approximately $99,000 on April 16, 2007.

     Also in conjunction with the Combination described in Note A — Organization and nature of operations and the conversion of CEHC preferred stock into Resources common stock at the ratio of 0.75:1, the CEHC Bundled Capital Options were converted into Resources Bundled Capital Options and CEHC Capital Options were converted into Resources Capital Options. The Resources Capital Options are considered to be exercisable for 1.25 shares of Resources common stock.

     Treasury stock. On June 12, 2008, the restrictions on five executive officers’ restricted stock awards lapsed. Immediately upon the lapse of restriction, these executive officers were liable for certain federal income taxes on the value of such shares. In accordance with the Company’s 2006 Stock Incentive Plan and the applicable restricted stock award agreements, four of such officers elected to deliver shares to the Company to satisfy such tax liability, and the Company withheld 3,142 shares to be held as treasury stock in the approximate amount of $125,000, the amount of the executive officers’ federal tax liability.

Note H. Stock incentive plan

     The Concho Resources Inc. 2006 Stock Incentive Plan (together with applicable option agreements and restricted stock agreements, the “Plan”) provides for granting stock options and restricted stock awards to employees and individuals associated with the Company.

     All restricted shares are treated as issued and outstanding in the accompanying consolidated balance sheets. If a grantee terminates employment or other services prior the lapse date, the awarded shares are forfeited and cancelled and are no longer considered issued and outstanding, subject to the discretion of the compensation committee. A summary of the Company’s restricted stock awards during the six months ended June 30, 2008 is presented below:

		Number of				Grant date
		common shares				fair value
Restricted stock:
Outstanding at December 31, 2007			371,549
Shares granted			80,508			$	35.17
Shares cancelled / forfeited			(35,262	)
Lapse of restrictions			(37,001	)
Outstanding at June 30, 2008			379,794

     The Company recorded stock-based compensation for restricted stock of $468,000 and $560,000, which is recognized in General and administrative expense in the accompanying consolidated statement of operations, for the three months ended June 30, 2008 and 2007, respectively. The Company recorded stock-based compensation for restricted stock of $862,000 and $781,000, which is recognized in General and administrative expense in the accompanying consolidated statement of operations, for the six months ended June 30, 2008 and 2007, respectively. Future stock-based compensation expense related to restricted stock outstanding at June 30, 2008 for the remaining six months of 2008 and the years ending December 31, 2009, 2010 and 2011 is expected to be approximately $1,358,000, $1,930,000, $1,162,000 and $354,000, respectively.

     The income tax benefit recognized in the accompanying statement of operations for restricted stock was approximately $187,000 and $235,000 for the three months ended June 30, 2008 and 2007, respectively, and $341,000 and $327,000 for the six months ended June 30, 2008 and 2007, respectively. The Company had deductions in current taxable income of $771,000 and $340,000 for the three months ended June 30, 2008 and 2007, respectively, and $1.2 million and $425,000 for the six months ended June 30, 2008 and 2007, respectively, related to restricted stock awards.

     Stock option awards. In calculating compensation expense for options granted during the six months ended June 30, 2008, the Company estimated the fair value of each grant using the Black-Scholes option-pricing model. Assumptions utilized in the model are shown below.

		2008
Risk-free interest rate			3.18	%
Expected term (years)			6.22
Expected volatility			37.28	%
Expected dividend yield			0.00	%

     As permitted by SAB No. 110, the Company used the simplified method to calculate the expected term for stock options granted during the three and six months ended June 30, 2008, since it does not have sufficient historical exercise data to provide a reasonable basis upon which to estimate expected term due to the limited period of time its shares of common stock have been publicly traded. Expected volatilities are based on a combination of historical and implied volatilities of comparable companies.

     A summary of the Company’s stock option activity under the Plan for the six months ended June 30, 2008 is presented below:

		Six months ended
		June 30, 2008
						Weighted
						Average
		Number of				Exercise
		options (a)				Price
Stock options:
Outstanding at beginning of period			3,011,722			$	9.71
Options granted			545,555			$	22.80
Options forfeited			(250,593	)		$	14.91
Options exercised			(262,713	)		$	9.03
Outstanding at end of period			3,043,971			$	11.69
Exercisable at end of period			717,236			$	10.21

     The following table summarizes information about the Company’s vested stock options outstanding and exercisable at June 30, 2008:

										Weighted
										average				Weighted
						Number				remaining				average
						vested and				contractual				exercise				Intrinsic
						exercisable				life				price				value
Vested Options
Exercise price		$	8.00				1,543,020			2.77 years				$	8.00			$	45,210,000
Exercise price		$	12.00				164,016			5.61 years				$	12.00				4,150,000
Exercise price		$	15.40				181,250			7.96 years				$	15.40				3,969,000
							1,888,286							$	9.06			$	53,329,000
Exercisable Options
Exercise price		$	8.00				454,224			3.42 years				$	8.00			$	13,309,000
Exercise price		$	12.00				106,762			7.28 years				$	12.00				2,701,000
Exercise price		$	15.40				156,250			7.96 years				$	15.40				3,422,000
							717,236							$	10.21			$	19,432,000

     The following table summarizes information about stock-based compensation for options which is recognized in General and administrative expense in the accompanying consolidated statement of operations 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
Grant date fair value:
Time Vesting options (a)		$	—			$	—			$	183,000			$	—
Current officer stock options (c)			794,000				—				5,090,000				—
Total		$	794,000			$	—			$	5,273,000			$	—
Stock-based compensation expense from stock options:
Time Vesting options (a)		$	35,000			$	—			$	65,000			$	—
Performance Vesting options:
Officers (b)			123,000				141,000				264,000				279,000
Certain employee (b)			10,000				10,000				20,000				20,000
Current officer stock options (c)			1,094,000				418,000				1,818,000				874,000
Total		$	1,262,000			$	569,000			$	2,167,000			$	1,173,000

     Future stock-based compensation expense related to stock options outstanding at June 30, 2008 for the remaining six months ended December 31, 2008 and the years ending December 31, 2009, 2010, 2011 and 2012 is expected to be approximately $2,288,000, $2,553,000, $1,151,000, $419,000 and $42,000, respectively.

     The income tax benefit recognized in the Company’s statements of operations for stock options was $504,000 and $239,000 for the three months ended June 30, 2008 and 2007, respectively, and $858,000 and $492,000 for the six months ended June 30, 2008 and 2007, respectively. The Company had deductions in current taxable income of $3.1 million for the three months ended June 30, 2008, as options on 119,961 shares of common stock were exercised during such quarter. No amounts were treated as deductions to the Company’s current taxable income for the three months ended June 30, 2007, since no options were exercised during such quarter. The Company had deductions in current taxable income of $5.3 million for the six months ended June 30, 2008, as options on 262,713 shares of common stock were exercised during such period. No amounts were treated as deductions to the Company’s current taxable income for the six months ended June 30, 2007, since no options were exercised during such quarter.

Note I. Derivative financial instruments

     Cash flow hedges. The Company, from time to time, uses derivative financial instruments as cash flow hedges of its commodity price risks. Commodity hedges are used to (a) reduce the effect of the volatility of price changes on the natural gas and crude oil the Company produces and sells and (b) support the Company’s annual capital budgeting and expenditure plans.

     Through December 31, 2006, the Company had entered into certain natural gas and crude oil zero cost price collars and crude oil price swaps to hedge a portion of its estimated natural gas and crude oil production for calendar years 2007 and 2008.

     On February 8, 2007, the Company entered into one natural gas price swap to hedge an additional portion of its estimated natural gas production for the period of March through December 2007. The contract is for 2,100 MMBtu per day at a fixed index price of $7.40 per MMBtu. The index price is based on the Inside FERC — El Paso Permian Basin spot price at the first of each month. On the respective trade dates, the Company has designated all of these derivative instruments as cash flow hedges.

     During the three months ended September 30, 2007, the Company determined that all of its natural gas commodity contracts no longer qualified as hedges under the requirements of SFAS No. 133 for the reason stated in the following paragraph. These contracts are referred to as “dedesignated hedges.”

     A key requirement for designation of derivative instruments as cash flow hedges is that at both at inception of the hedge and on an ongoing basis, the hedging relationship is expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. Generally, the hedging relationship can be considered to be highly effective if there is a high degree of historical correlation between the hedging instrument and the forecasted transaction. For all quarters ended prior to July 1, 2007, prices received for the Company’s natural gas were highly correlated with the Inside FERC – El Paso Natural Gas index (the “Index”) – the Index referenced in all of the Company’s natural gas derivative instruments. However, during the quarter ended September 30, 2007, this historical relationship has not met the criteria as being highly correlated. Natural gas produced from the Company’s New Mexico shelf assets has a substantial component of natural gas liquids. Prices received for natural gas liquids are not highly correlated to the price of natural gas, but are more closely correlated to the price of oil. During the third quarter of 2007, the price of oil and natural gas liquids, and therefore, the prices the Company received for its natural gas (including natural gas liquids) have risen substantially and at a significantly higher rate than the corresponding change in the Index. This has resulted in a decrease in correlation between the prices received and the Index below the level required for cash flow hedge accounting. According to SFAS No. 133, an entity shall discontinue hedge accounting prospectively for an existing hedge if the hedge is no longer highly effective. Hedge accounting must be discontinued regardless of whether the Company believes the hedge will be prospectively highly effective. The hedge must be discontinued during the period the hedges became ineffective. As a result, any changes in fair value must be recorded in earnings under (Gain) loss on derivatives not designated as hedges. Because the gas and liquids prices fluctuate at different rates over time, the loss of effectiveness does not relate to any single date.

     Therefore, June 30, 2007, was considered the last date the Company’s natural gas hedges were highly effective, and the Company discontinued hedge accounting during the three months ended September 30, 2007 and all periods thereafter. Mark-to-market adjustments related to these dedesignated hedges is recorded each period to (Gain) loss on derivatives not designated as hedges. Effective portions of dedesignated hedges, previously recorded in Accumulated other comprehensive income (“AOCI”) as of June 30, 2007, remain in AOCI and are being reclassified into earnings under Natural gas revenues, during the periods which the hedged forecasted transaction affects earnings.

     Derivatives not designated as cash flow hedges. During the six months ended June 30, 2008, the Company entered into crude oil price swaps, a crude oil costless collar and a natural gas price swap to hedge a portion of its estimated production for the remainder of 2008, and for calendar years 2009, 2010, 2011 and 2012. The following table summarizes information about these new derivative instruments as of June 30, 2008:

Aggregate

remaining

Daily

Index

Contract

volume

volume

price

period

Derivatives not designated as cash flow hedges:

Crude oil (volumes in Bbls):

Price collar

768,000

2,104

$120.00 - $134.60 (a)

1/1/09 - 12/31/09

Price swap

258,000

1,400

$99.25 (a)

7/1/08 - 12/31/08

Price swap

292,000

800

$98.35 (a)

1/1/09 - 12/31/09

Price swap

240,000

658

$128.80 (a)

1/1/10 - 12/31/10

Price swap

336,000

921

$128.66 (a)

1/1/11 - 12/31/11

Price swap

504,000

1,377

$127.80 (a)

1/1/12 - 12/31/12

Natural gas (volumes in MMBtus):

Price swap

1,825,000

5,000

$8.44 (b)

1/1/09 - 12/31/09

The Company has not designated these derivative instruments as cash flow hedges. Mark-to-market adjustments related to these derivative instruments are recorded each period to (Gain) loss on derivatives not designated as hedges.

     Fair value and activity of derivative instruments. The following table sets forth the Company’s outstanding crude oil and natural gas zero cost price collars and price swaps at June 30, 2008:

		Fair Market Value				Aggregate
		Liability				remaining				Daily				Index		Contract
		(in thousands)				volume				volume				price		period
Cash flow hedges:
Crude oil (volumes in Bbls):
Price swap		$	(34,958	)			478,400				2,600			$67.50 (a)			7/1/08 - 12/31/08
Cash flow hedges dedesignated:
Natural gas (volumes in MMBtus):
Price collar			(7,348	)			2,484,000				13,500			$6.50 - $9.35 (b)			7/1/08 - 12/31/08
Derivatives not designated as cash flow hedges:
Crude oil (volumes in Bbls):
Price collar			(8,578	)			768,000				2,104			$120.00 - $134.60 (a)			1/1/09 - 12/31/09
Price swap			(34,558	)			625,600				3,400			$85.44 (a) (c)			7/1/08 - 12/31/08
Price swap			(60,264	)			1,022,000				2,800			$80.13 (a) (c)			1/1/09 - 12/31/09
Price swap			(2,182	)			240,000				658			$128.80 (a)			1/1/10 - 12/31/10
Price swap			(2,522	)			336,000				921			$128.66 (a)			1/1/11 - 12/31/11
Price swap			(3,785	)			504,000				1,377			$127.80 (a)			1/1/12 - 12/31/12
Natural gas (volumes in MMBtus):
Price swap			(5,133	)			1,825,000				5,000			$8.44 (b)			1/1/09 - 12/31/09
Net liability		$	(159,328	)

     The following table sets forth the Company’s classification of derivative instruments as of June 30, 2008:

		Fair Market Value
(in thousands)		Liability
Derivative liabilities:
Short-term			(114,504	)
Long-term			(44,824	)
Net liability		$	(159,328	)

     The Company’s reported oil and gas revenue and average oil and gas prices includes the effects of oil quality and Btu content, gathering and transportation costs, gas processing and shrinkage, and the net effect of the commodity hedges. The following table summarizes the gains and losses reported in earnings related to the commodity financial instruments and the net change in AOCI:

		Three months ended								Six months ended
		June 30,								June 30,
(in thousands)		2008				2007				2008				2007
Increase (decrease) in oil and gas revenue from derivative activity:
Cash (payments) receipts on cash flow hedges in oil sales		$	(13,367	)		$	(783	)		$	(20,573	)		$	244
Cash receipts from cash flow hedges in gas sales			—				49				—				187
Dedesignated cash flow hedges reclassified from AOCI in gas sales			74				—				(222	)			—
Total increase (decrease) in oil and gas revenue from derivative activity		$	(13,293	)		$	(734	)		$	(20,795	)		$	431
Loss on derivatives not designated as cash flow hedges:
Mark-to-market		$	(90,055	)		$	—			$	(103,247	)		$	—
Cash payments on derivatives not designated as cash flow hedges			(12,401	)			—				(16,387	)			—
Total loss on derivatives not designated as cash flow hedges		$	(102,456	)		$	—			$	(119,634	)		$	—
Gain (loss) from ineffective portion of cash flow hedges		$	356			$	99			$	920			$	(1,156	)
Accumulated other comprehensive income (loss):
Cash flow hedges:
Mark-to-market of cash flow hedges gain (loss)		$	(25,903	)		$	992			$	(32,510	)		$	(7,457	)
Reclassification adjustment for (gains) losses included in net income			13,367				734				20,573				(431	)
Net change, before taxes			(12,536	)			1,726				(11,937	)			(7,888	)
Tax effect			4,899				(724	)			4,665				3,288
Net change, net of tax		$	(7,637	)		$	1,002			$	(7,272	)		$	(4,600	)
Dedesignated cash flow hedges:
Reclassification adjustment for (gains) losses included in net income		$	(74	)		$	—			$	222			$	—
Tax effect			29				—				(87	)			—
Net change, net of tax		$	(45	)		$	—			$	135			$	—

     All of the Company’s derivatives are expected to settle by December 31, 2012. Based on futures prices as of June 30, 2008, the Company expects a pre-tax loss of $34.5 million to be reclassified into earnings and a pre-tax loss of $0.5 million to be reclassified out of AOCI into earnings during the six months ended December 31, 2008 related to the cash flow hedges and the dedesignated cash flow hedges, respectively.

Note J. Long-term debt

     The Company’s long-term debt consisted of the following as of the dates indicated:

		June 30,				December 31,
(in thousands)		2008				2007
Bank debt:
1st Lien Credit Facility		$	190,000			$	216,000
New 2nd Lien Credit Facility			108,900				109,900
Unamortized original issue discount on New 2nd Lien Credit Facility			(447	)			(496	)
Total long-term debt		$	298,453			$	325,404
Current portion of New 2nd Lien Credit Facility			2,500				2,000
Total debt		$	300,953			$	327,404

     Refinancing of debt facilities. As of March 27, 2007, the Company amended its revolving credit facility (“1st Lien Credit Facility”) with a syndicate of banks (“1st Lien Banks”), repaid its term loan facility, and entered into a new second lien credit facility (the “New 2nd Lien Credit Facility”), for a term loan facility in the amount of $200 million. The full amount of the facility was funded on the closing date. The New 2nd Lien Credit Facility was issued at a discount of 0.5 percent; thus, the Company received proceeds of $199.0 million. The proceeds from the borrowing were used to repay the existing second lien credit facility in full in the amount of $39.8 million without penalty, reduce the amount outstanding under the 1st Lien Credit Facility by $154.0 million, with the remaining $5.2 million used to pay loan fees, accrued interest and for general corporate purposes. The amount outstanding under the 1st Lien Credit Facility at June 30, 2008 was $190.0 million.

     The amendment of the 1st Lien Credit Facility on March 27, 2007, resulted in a $100 million, or 21 percent, reduction of the borrowing base. As such, the pro rata portion of the remaining debt issuance costs associated with the 1st Lien Credit Facility, totaling approximately $766,000, was written off and included in Interest expense in the first quarter of 2007. The remaining debt issuance costs of $433,000 associated with the term loan facility repaid in full on March 27, 2007, were written off and included in Interest expense in the first quarter of 2007.

     The Company paid an arrangement fee of $2.5 million at the date of closing of the New 2nd Lien Credit Facility. This fee is being amortized to Interest expense over the five-year term of the facility beginning in April 2007.

     The Company entered into the Third Amendment to the 1st Lien Credit Facility on May 19, 2008, which redetermined the borrowing base under the 1st Lien Credit Facility to $550 million at June 30, 2008 and extended the maturity date to February 24, 2011. The Company incurred approximately $1.0 million in deferred loan costs associated with this amendment. These costs will be amortized to Interest expense over the new term of the facility.

     The New 2nd Lien Credit Facility provides a $200 million term loan, which bears interest, at the Company’s option, based on (a) the Bank of America Prime Rate (5.00 percent at June 30, 2008) or (b) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). The interest rates of Eurodollar rate advances and prime rate advances vary, with interest margins of 375 basis points and 225 basis points, respectively, until August 7, 2007, when the Company completed its initial public offering; thereafter, interest margins on Eurodollar rate advances and prime rate advances increased to 425 basis points and 275 basis points, respectively. The Company may select interest periods on Eurodollar rate advances of one, two, three, six, nine and twelve months, subject to availability. Interest is payable at the end of the selected interest period, but no less frequently than quarterly.

     The Company is required to repay $0.5 million of the New 2nd Lien Credit Facility on the last day of each calendar quarter. These payments began on June 30, 2007. The maturity date of the New 2nd Lien Credit Facility is March 27, 2012. The Company has the right to prepay the outstanding balance under the New 2nd Lien Credit Facility at any time; however, a two percent prepayment penalty will be incurred on any principal amount prepaid during the second year following the closing and one percent penalty will be incurred during the third year following the closing. Thereafter, no prepayment penalty will be incurred.

     Borrowings under the New 2nd Lien Credit Facility are secured by a second lien on the same assets as are securing the 1st Lien Credit Facility. The second lien is subordinated only to liens securing the 1st Lien Credit Facility. The New 2nd Lien Credit Facility contains various restrictive covenants including (a) maintenance of certain financial ratios including (i) maintenance of a quarterly ratio of total debt to consolidated earnings before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and other non-cash income and expenses of less than 4.5 to 1.0, (ii) maintenance of a ratio of current assets to

current liabilities, excluding non-cash assets and liabilities related financial derivatives and asset retirement obligations, to be greater than 1.0 to 1.0 and (iii) maintenance of a ratio, as of January 1 and June 30 of each year, of the net present value of the Company’s oil and gas properties to total debt to be greater than 1.5 to 1.0; (b) limits on the incurrence of additional indebtedness and certain types of liens; (c) restrictions as to merger and sale or transfer of assets; and (d) a restriction on the payment of cash dividends. The Company was in compliance with all covenants of the New 2nd Lien Credit Facility at June 30, 2008.

     The amount outstanding under New 2nd Lien Credit Facility at June 30, 2008 was $111.0 million, net of a discount of $0.4 million, all of which was at the Eurodollar rate.

     Repayment of a portion of New 2nd Lien Credit Facility. As described in Note A — Organization and nature of operations, IPO proceeds in the amount of $86.6 million were used to repay a portion of the New 2nd Lien Credit Facility on August 9, 2007. Subsequent to such repayment the outstanding balance, net of remaining original issue discount, as of August 9, 2007, was $112.4 million. As set forth by this facility’s credit agreement, effective on the consummation of the IPO, the interest margins on Eurodollar rate advances and prime rate advances increased to 425 basis points and 275 basis points, respectively, and remain in effect at June 30, 2008.

     A pro rata portion of the deferred loan costs associated with the New 2nd Lien Credit Facility were written off to Interest expense in August 2007 in the amount of approximately $1.0 million. Additionally, a pro rata portion of the unamortized original issue discount related to the New 2nd Lien Credit Facility was written off to Interest expense in August 2007 in the amount of approximately $0.4 million.

     Principal maturities of long-term debt. Principal maturities of long-term debt outstanding, excluding the unamortized discount of approximately $0.4 million, at June 30, 2008, for the six months ended December 31, 2008 and the years ended December 31, 2009, 2010, 2011 and 2012, are as follows:

(in thousands)
2008		$	1,500
2009			2,000
2010			192,000
2011			2,000
2012			103,900
Total		$	301,400

     As of July 31, 2008, the Company amended its 1st Lien Credit Facility, increasing the borrowing base 75% from $550 million to $960 million and extended the maturity date from February 24, 2011 to July 31, 2013. See further discussion in Note O — Subsequent events.

Note K. Commitments and contingencies

     Daywork drilling contract commitments. The Company signed a daywork drilling contract with a drilling contractor on July 20, 2006, that provided the Company exclusive use of one rig with an operating day rate of $15,500 for a term that commenced on August 1, 2006 and ended on June 15, 2007. During February 2007, management decided to stack this rig due to budget modifications. The Company incurred contract drilling fees of approximately $1.3 million related to this stacked rig during the year ended December 31, 2007. These costs were minimized as the drilling contractor secured work for the rig and refunded the Company the difference between the current operating day rate pursuant to the contract and the operating day rate received from the new customer.

     The Company signed a new daywork drilling contract with the drilling contractor on June 26, 2007, that provided the Company exclusive use of one rig for a term that commenced on July 3, 2007 and ended on January 3, 2008. The Company may direct the rig to locations within the Permian Basin region as needed. The Company is solely responsible and assumes liability for all consequences of operations by both parties while on a daywork basis, with the exception that the drilling contractor is liable for its employees, subcontractors and invitees. In addition, the drilling contractor is responsible for pollution or contamination from their equipment. The drilling contractor will release the Company of any liability for negligence of any party in connection with the drilling contractor. The operating day rate is $14,000. The operating day rate can be revised to reflect changes in costs incurred by the drilling contractor for labor and/or fuel. The contract allows an early termination by the Company with at least a thirty day notice and a payment of the lump sum termination amount equal to the current operating day rate less $6,000, multiplied by the days remaining through the end of the contract term. However, if the drilling contractor secures work for the subject rig with a new customer prior to the end of the contract

term, the drilling contractor will rebate the Company the difference between the current operating day rate pursuant to the contract and the operating day rate received from the new customer. Beginning on January 4, 2008, this contract was extended through July 31, 2008. The amended contract changed the operating day rate from $14,000 to $13,250. Beginning on March 12, 2008, this contract was amended to change the operating day rate from $13,250 to $12,850 and to extend the term through July 31, 2009. On June 24, 2008, this contract was amended to include an additional rig with an operating day rate of $13,250 for a term ending on July 15, 2009.

     The Company signed daywork drilling contracts with Silver Oak Drilling, LLC (“Silver Oak”), an affiliate of the Chase Group, on August 1, 2006, that provided the Company use of four drilling rigs for a term that commenced on August 1, 2006 and ended on July 31, 2007. The Company could direct the rig to locations located in New Mexico as needed. If the Company moved the rig out of certain New Mexico counties specified in the contract, all effective daywork rates will be increased by an additional $2,000 per day. The Company was solely responsible and assumes liability for all consequences of operations by both parties while on a daywork basis, with the exception that Silver Oak was liable for its employees, subcontractors and invitees. In addition, Silver Oak was responsible for pollution or contamination from their equipment. Silver Oak released the Company of any liability for negligence of any party connected to Silver Oak. The operating day rate was $14,500 for two of the contracts and $13,500 for the other two contracts. The operating day rate could be revised to reflect changes in costs incurred by more than 5 percent by Silver Oak for labor, insurance premiums, fuel, and/or an increase in the number of Silver Oak’s personnel needed. Under the contracts, the Company must pay the full operating day rate for each day during the contract term. Although there is no early termination provision in the contracts, Silver Oak had a duty to mitigate damages to the Company by reasonably attempting to secure replacement contracts for the rigs if they were released by the Company or if any contract is terminated by Silver Oak prior to the expiration of the term of the contract. The Company would then be entitled to a 75 percent credit for any revenues received by Silver Oak. Even if the Company released the rigs, the Company, with 20 days notice, could withdraw its release and reactivate the contract for the remainder of the term to the extent the rig had not been committed to a third party in mitigation of the Company’s damages. During February 2007, management decided to stack these four rigs due to budget modifications. The Company incurred contract drilling fees of approximately $2,973,000 related to these stacked rigs during the year ended December 31, 2007, based on the drilling contracts described above. As of April 1, 2007, the Company began to utilize all four rigs, in order to proceed with its 2007 drilling budget.

     The Company signed new daywork drilling contracts with Silver Oak on June 19, 2007, that provides the Company use of four drilling rigs for a term that commenced on August 1, 2007 and are in effect until drilling operations are completed on specified wells or for a term of one year. If any well commenced during the term of the contract is drilling at the expiration of the one year primary term, drilling will continue under the terms of the contract until drilling operations for that well have been completed. The Company may direct the rig to locations located in New Mexico as needed. The Company is solely responsible and assumes liability for all consequences of operations by both parties while on a daywork basis, with the exception that Silver Oak is liable for its employees, subcontractors and invitees. In addition, Silver Oak is responsible for pollution or contamination from their equipment. Silver Oak will release the Company of any liability for negligence of any party connected to Silver Oak. The operating day rate is $14,500 for two of the contracts and $13,500 for the other two contracts. The operating day rate can be revised to reflect changes in costs incurred by more than 5 percent by Silver Oak for labor, insurance premiums, fuel, and/or an increase in the number of Silver Oak’s personnel needed. Under the contract, the Company must pay the full operating day rate for each day during the contract term. Although there is no early termination provision in the contract, Silver Oak has a duty to mitigate damages to the Company by reasonably attempting to secure replacement contracts for the rigs if they are released by the Company or if any contract is terminated by Silver Oak prior to the expiration of the term of the contract. The Company will then be entitled to a 75 percent credit for any revenues received by Silver Oak. Even if the Company releases the rigs, the Company, with 20 days notice, may withdraw its release and reactivate the contracts for the remainder of the term to the extent the subject rig has not been committed to a third party in mitigation of damages. Beginning on June 30, 2008, these contracts were amended to change the operating day rates from $14,500 to $15,000 and from $13,500 to $14,000 and to extend the term through August 1, 2009.

Note L. Income taxes

     The Company accounts for income taxes in accordance with the provisions of SFAS No. 109 “Accounting for Income Taxes.” The Company and its subsidiaries file federal corporate income tax returns on a consolidated basis. The tax returns and the amount of taxable income or loss are subject to examination by United States federal and state taxing authorities. In determining the interim period income tax provision, the Company utilizes an estimated annual effective tax rate.

     The Company adopted the provisions of FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN No. 48”) an interpretation of FASB Statement No. 109 “Accounting for Income Taxes,” on January 1, 2007. At the time of adoption and as of June 30, 2008, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2004 through 2007 remain subject to examination by major tax jurisdictions.

     The FASB issued FIN No. 48-1, “Definition of Settlement in FASB Interpretation No. 48,” (“FIN No. 48-1”) to clarify when a tax position is effectively settled. FIN No. 48-1 provides guidance in determining the proper timing for recognizing tax benefits and applying the new information relevant to the technical merits of a tax position obtained during a tax authority examination. FIN No.

48-1 provides criteria to determine whether a tax position is effectively settled after completion of a tax authority examination, even if the potential legal obligation remains under the statute of limitations. The Company’s adoption of this pronouncement did not have a significant effect on its consolidated financial statements.

     The Company’s provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes and non-deductible expenses.

Note M. Related parties

     Contract Operator Agreement and Transition Services Agreement. On February 27, 2006, the Company signed a Contract Operator Agreement with Mack Energy Corporation (“MEC”), an affiliate of the Chase Group, whereby the Company engaged MEC as contract operator to provide certain services with respect to the Chase Group Properties. The initial term of the Contract Operator Agreement was 5 years commencing on March 1, 2006 and ending on February 28, 2011. The Company and MEC entered into a Transition Services Agreement on April 23, 2007, which terminated the Contract Operator Agreement and under which MEC continued to provide certain field level operating services on the Chase Group Properties. Under the Transition Services Agreement, MEC provided field level services, including pumping, well service oversight and supervision and certain equipment for workover and recompletion services, at costs prevailing in the area of the subject properties, but not to exceed charges for comparable services by and among MEC and its affiliates. MEC performed substantially similar services on behalf of the Company under the prior Contract Operator Agreement prior to its termination. In accordance with its terms, the Transition Services Agreement was terminated automatically by its terms on August 7, 2007 upon the Company’s completion of the IPO. Upon termination, the Company’s employees along with third party contractors assumed the operation of the subject properties.

     The Company incurred charges from MEC of approximately $260,000 and $1.5 million for the three and six months ended June 30, 2008, respectively.

     The Company incurred charges from MEC of approximately $5.1 million and $10.2 million for the three and six months ended June 30, 2007, respectively, for services rendered under the Contract Operator Agreement and Transition Services Agreement.

     At June 30, 2008, the Company had outstanding invoices payable to MEC of approximately $5,000 which are reflected in Accounts payable—related parties in the accompanying consolidated balance sheet.

     At December 31, 2007, the Company had outstanding invoices payable to MEC of approximately $0.4 million which are reflected in Accounts payable—related parties in the accompanying consolidated balance sheet.

     Other related party transactions. The Company also has engaged in transactions with certain other affiliates of the Chase Group, including Silver Oak, an oilfield services company, a supply company, a drilling fluids supply company, a pipe and tubing supplier, a fixed base operator of aircraft services and a software company.

     The Company incurred charges from these related party vendors of approximately $5.7 million and $13.1 million for the three and six months ended June 30, 2008, respectively, for services rendered and charges of approximately $10.7 million and $22.1 million for the three and six months ended June 30, 2007, respectively, for services rendered.

     The Company had outstanding invoices payable to the other related party vendors identified above of approximately $264,000 and $1.7 million at June 30, 2008 and December 31, 2007, respectively, which are reflected in Accounts payable—related parties in the accompanying consolidated balance sheets.

     Overriding royalty and royalty interests. Certain members of the Chase Group own overriding royalty interests in certain of the Chase Group Properties. The amount paid attributable to such interests was approximately $816,000 and $1.6 million for the three and six months ended June 30, 2008, respectively. The amount paid attributable to such interests was approximately $458,000 and $1.0 million for the three and six months ended June 30, 2007, respectively. The Company owed these owners royalty payments of approximately $322,000 and $315,000 as of June 30, 2008 and December 31, 2007, respectively.

     Royalties are paid on certain properties located in Andrews County, Texas to a partnership of which one of the Company’s directors is the general partner, and who also owns a 3.5% partnership interest. The Company paid this partnership approximately $81,000 and $164,000 for the three and six months ended June 30, 2008, respectively. The Company paid approximately $36,000 and $59,000 for the three and six months ended June 30, 2007, respectively. The Company owed this partnership royalty payments of approximately $30,000 and $29,000 as of June 30, 2008 and December 31, 2007, respectively.

     In April 2005, the Company acquired certain working interests in 46,861 gross (26,908 net) acres located in Culberson County, Texas from an entity partially owned by a person who became an executive officer of the Company immediately following such

acquisition. In connection with this acquisition, such entity retained a 2% overriding royalty interest in the acquired properties, which overriding royalty interest later became owned equally by such officer and a non-officer employee of the Company. During the three and six months ended June 30, 2008, no payments were made related to this overriding royalty interest. The amount attributable to such interest was approximately $2,000 during the three and six months ended June 30, 2007. Effective March 31, 2008, the referenced executive officer resigned from the Company.

     Prospect participation. Subsequent to the closing of the Combination, the Company acquired working interests from Caza in certain lands in New Mexico in which Caza owns an interest.

     There were no amounts paid to Caza for these interests during the three and six months ended June 30, 2008, and during the three months ended June 30, 2007. The Company paid Caza approximately $3,000 for the six months ended June 30, 2007 for delay rentals.

     At June 30, 2008 and December 31, 2007, the Company had no outstanding invoices owed to Caza.

Note N. Net income per share

     Basic net income per share is computed by dividing net income applicable to common shareholders by the weighted average number of common shares treated as outstanding for the period. As discussed in Note G — Stockholders’ equity and stock issued subject to limited recourse notes , agreements to sell stock to the Officers and certain employees subject to Purchase Notes are accounted for as options (“Bundled Capital Options” and “Capital Options”, respectively). As a result, Bundled Capital Options and Capital Options are excluded from the weighted average number of common shares treated as outstanding during each period until the Purchase Notes are paid in full, thus exercising the options. All Bundled Capital Options were exercised prior to June 30, 2007. All Capital Options were exercised prior to March 31, 2008.

     The computation of diluted income per share reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive to income were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. These amounts include unexercised Bundled Capital Options, Capital Options, stock options and restricted stock (as issued under the Plan, as described in Note H — Stock incentive plan. Potentially dilutive effects are calculated using the treasury stock method.

     The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2008 and 2007:

		Three months ended								Six months ended
		June 30,								June 30,
(in thousands)		2008				2007				2008				2007
Weighted average common shares outstanding:
Basic			75,665				57,747				75,569				56,369
Dilutive Bundled Capital Options			—				660				—				1,695
Dilutive Capital Options			—				160				12				204
Dilutive common stock options			—				996				1,206				921
Dilutive restrictive stock			—				62				247				71
Diluted			75,665				59,625				77,034				59,260

     For the three months ended June 30, 2008, the computation of diluted net loss per share was antidilutive; therefore, the amounts reported for basic and diluted net loss per share were the same. Restricted stock and options equivalent to 379,794 and 3,043,971 shares of common stock were not included in the computation of diluted income (loss) per share for the three months ended June 30, 2008, respectively, as inclusion of these items would be antidilutive.

     For the three and six months ended June 30, 2007, and for the six months ended June 30, 2008, the effects of all potentially dilutive securities including Bundled Capital Options, Capital Options and stock options were included in the computation of diluted earnings per share because the Company had net income applicable to common shareholders and, therefore, there were no antidilutive effects.

Note O. Subsequent events

     New derivative instruments. On July 25, 2008, the Company entered into two crude oil price swaps to hedge a portion of its estimated crude oil production for calendar years 2008 and 2009. The contracts are for 49,000 Bbls per month for the remainder of 2008 (August through December) at a fixed price of $124.35 per Bbl, and 29,000 Bbls per month for calendar year 2009 at a fixed price of $125.10 per Bbl. The Company has not designated these derivative instruments as cash flow hedges. Mark-to-market adjustments related to these derivative instruments will be recorded each period to (Gain) loss on derivatives not designated as hedges.

     Henry Acquisition. On July 31, 2008, the Company closed the acquisition of Henry Petroleum LP and certain affiliated entities (collectively “Henry”) (the “Acquisition”). Cash paid at closing totaled approximately $560 million. The Company financed the Acquisition with proceeds raised from a $250.0 million private placement of 8.3 million shares of the Company’s common stock, together with funds available under a new amended and restated senior credit facility (the “Senior Credit Facility”), as further described below. After the closing of the Henry transaction and the additional interests acquired concurrently as described below, the Company has approximately $285 million of availability under the Senior Credit Facility.

     In connection with the Acquisition, the Company also purchased certain additional non-operated rights and interests in Henry’s oil and gas properties from certain persons affiliated with Henry (such transactions, collectively, the “Along-side Transactions”) for aggregate cash consideration of approximately $28.0 million.

     The following table shows the sources and uses of funds for the above referenced transactions on July 31, 2008:

(in thousands)
Sources of Funds:
Proceeds from Issuance of Common Shares		$	250,000
Initial Borrowing under Senior Credit Facility			675,000
Total Sources of Funds		$	925,000
Uses of Funds:
Purchase of Henry Equity Interests		$	536,830
Repay 1st Lien Credit Facility			194,389
Repay 2nd Lien Credit Facility			113,189
Purchase of Along-side Property Interests			28,039
Fees and Expenses			24,829
Working Capital and General Corporate Purposes			27,724
Total uses of Funds		$	925,000

          Common Stock Purchase Agreement. On June 5, 2008, the Company also entered into a Common Stock Purchase Agreement (the “Purchase Agreement”) with certain unaffiliated third-party investors (the “Purchasers”) to sell approximately 8.3 million shares of the Company’s common stock in a private placement (the “Private Placement”) for aggregate cash consideration of approximately $250.0 million, for a negotiated price of $30.11 per share. The Private Placement closed simultaneously with the Acquisition on July 31, 2008.

     The closing of the Private Placement was subject to customary closing conditions, as well as certain other conditions, including (i) the closing of the Acquisition and (ii) the execution by the Company and the Purchasers of a registration rights agreement that will require the Company to file a shelf registration statement for the benefit of the Purchasers within 60 days after the closing of the Private Placement.

     The Private Placement is being made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, pursuant to Section 4(2) thereof.

          Amended and Restated Credit Facility. As of July 31, 2008, the Company amended and restated its senior credit facility in various respects including, increasing the borrowing base to $960 million, subject to semiannual redetermination, and extending the maturity date from February 24, 2011 to July 31, 2013 (the “Senior Credit Facility,” as defined above). The initial borrowing under the Senior Credit Facility was

$675 million. The Company paid an arrangement fee of $14.4 million at the date of closing of the Senior Credit Facility. This fee is being amortized to Interest expense over the remaining five year term of the facility beginning in August 2008.

     Advances on the Senior Credit Facility bear interest, at the Company’s option, based on (a) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) (5.00 percent at July 31, 2008) or (b) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). The interest rates of Eurodollar rate advances and JPM Prime Rate advances vary, with interest margins ranging from 125 - 275 basis points and 0 - 125 basis points, respectively, per annum depending on the balance outstanding. The Company pays commitment fees on the unused portion of the available borrowing base ranging from 25 - 50 basis points per annum.

     The Senior Credit Facility also includes a same-day advance facility under which the Company may borrow funds on a daily basis from the 1st Lien Banks’ administrative agent. Advances made on this same-day basis cannot exceed $25 million and the maturity dates cannot exceed fourteen days. The interest rate on this facility is the JPM Prime Rate plus the applicable interest margin.

     The Company’s obligations under the Senior Credit Facility are secured by a first lien on substantially all of the Company’s oil and gas properties. In addition, all of the Company’s subsidiaries are guarantors, and all subsidiary general partner, limited partner and membership interests owned by the Company have been pledged to secure borrowings under the Senior Credit Facility. The credit agreement contains various restrictive covenants and compliance requirements which include (a) maintenance of certain financial ratios (i) maintenance of a quarterly ratio of total debt to consolidated earnings before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and other noncash income and expenses no greater than 4.0 to 1.0, and (ii) maintenance of a ratio of current assets to current liabilities, excluding noncash assets and liabilities related to financial derivatives and asset retirement obligations, to be no less than 1.0 to 1.0; (b) limits on the incurrence of additional indebtedness and certain types of liens; (c) restrictions as to merger and sale or transfer of assets; and (d) a restriction on the payment of cash dividends.

Note P. Supplementary information

Capitalized costs

		June 30,				December 31,
(in thousands)		2008				2007
Oil and gas properties:
Proved		$	1,432,392			$	1,303,665
Unproved			242,771				251,353
Less accumulated depletion			(209,688	)			(167,109	)
Net capitalized costs for oil and gas properties		$	1,465,475			$	1,387,909

Costs incurred for oil and gas producing activities

		Three months ended								Six months ended
		June 30,								June 30,
(in thousands)		2008				2007				2008				2007
Property acquisition costs:
Proved		$	(104	)		$	113			$	1			$	113
Unproved			587				3,001				1,349				3,791
Exploration			20,942				30,027				50,507				41,734
Development			45,146				2,072				70,799				17,373
Capitalized asset retirement obligations			1,412				(922	)			637				(1,289	)
Total costs incurred for oil and gas properties		$	67,983			$	34,291			$	123,293			$	61,722