Concho Resources (CXO) 10-Q 2010 Q2 Quarterly report

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, 2010

or

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

For the transition period from                    to                    

Commission file number: 1-33615

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 100
Midland, Texas	79701
(Address of principal executive offices)	(Zip code)

(432) 683-7443

(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. Yesþ     Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesþ      Noo

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 filerþ Accelerated filero Non-accelerated filero(Do not check if a smaller reporting company) Smaller reporting companyo

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

Number of shares of the registrant’s common stock outstanding at August 4, 2010: 91,842,832 shares.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item 1.Consolidated Financial Statements (Unaudited)	iii
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations		41
Item 3.Quantitative and Qualitative Disclosures About Market Risk		60
Item 4.Controls and Procedures		61
PART II — OTHER INFORMATION
Item 1.Legal Proceedings		62
Item 1A.Risk Factors		62
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds		63
Item 5.Other Information		63
Item 6.Exhibits		64
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

i

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

     Various statements contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil and natural gas reserves, drilling program capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and the estimated purchase price of the acquisition of the assets of Marbob Energy Corporation and affiliates (“Marbob”), potential financing, closing timeline and other discussion of the Marbob acquisition. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by the forward-looking statements. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made; we disclaim any obligation to update or revise these statements unless required by securities law, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2009, as well as those factors summarized below:

• sustained or further declines in the prices we receive for our oil and natural gas;

• uncertainties about the estimated quantities of oil and natural gas reserves;

• uncertainty regarding the exercise of preferential purchase rights on assets to be acquired in the Marbob acquisitions;

• risks related to the integration of the Marbob assets and employees with our operations;

• drilling and operating risks;

• the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our credit facility;

• the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing;

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

• risks related to the concentration of our operations in the Permian Basin of Southeast New Mexico and West Texas;

• potential financial losses or earnings reductions from our commodity price risk management program;

• shortages of oilfield equipment, services and qualified personnel and increased costs for such equipment, services and personnel;

• risks and liabilities associated with acquired properties or businesses, including the Marbob assets;

• uncertainties about our ability to successfully execute our business and financial plans and strategies;

• uncertainties about our ability to replace reserves and economically develop our current reserves;

• general economic and business conditions, either internationally or domestically or in the jurisdictions in which we operate;

• competition in the oil and natural gas industry;

• uncertainty concerning our assumed or possible future results of operations; and

• our existing indebtedness.

     Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

ii

PART I — FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

Consolidated Balance Sheets at June 30, 2010 and December 31, 2009	1
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009	2
Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2010	3
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009	4
Condensed Notes to Consolidated Financial Statements	5

iii

Concho Resources Inc.
Consolidated Balance Sheets
Unaudited

	June 30,			December 31,
(in thousands, except share and per share data)	2010			2009
Assets
Current assets:
Cash and cash equivalents	$	383		$	3,234
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas		88,029			69,199
Joint operations and other		88,836			100,120
Related parties		395			216
Derivative instruments		32,409			1,309
Deferred income taxes		—			29,284
Prepaid costs and other		10,600			13,896
Total current assets		220,652			217,258
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		3,697,653			3,358,004
Accumulated depletion and depreciation		(630,255	)		(517,421	)
Total oil and natural gas properties, net		3,067,398			2,840,583
Other property and equipment, net		16,304			15,706
Total property and equipment, net		3,083,702			2,856,289
Deferred loan costs, net		20,771			20,676
Intangible asset, net — operating rights		35,748			36,522
Inventory		20,258			16,255
Noncurrent derivative instruments		62,164			23,614
Other assets		958			471
Total assets	$	3,444,253		$	3,171,085
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	5,982		$	15,443
Related parties		852			291
Other current liabilities:
Bank overdrafts		37,992			3,415
Revenue payable		30,172			31,069
Accrued and prepaid drilling costs		190,719			164,282
Derivative instruments		18,093			62,419
Deferred income taxes		3,530			—
Other current liabilities		60,308			60,095
Total current liabilities		347,648			337,014
Long-term debt		644,023			845,836
Deferred income taxes		664,222			603,286
Noncurrent derivative instruments		5,678			29,337
Asset retirement obligations and other long-term liabilities		20,335			20,184
Commitments and contingencies (Note K)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 91,851,690 and 85,815,926 shares issued at June 30, 2010 and December 31, 2009, respectively		92			86
Additional paid-in capital		1,265,179			1,029,392
Retained earnings		498,078			306,367
Treasury stock, at cost; 23,667 and 12,380 shares at June 30, 2010 and December 31, 2009, respectively		(1,002	)		(417	)
Total stockholders’ equity		1,762,347			1,335,428
Total liabilities and stockholders’ equity	$	3,444,253		$	3,171,085

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

1

Concho Resources Inc.
Consolidated Statements of Operations
Unaudited

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands, except per share amounts)	2010			2009			2010			2009
Operating revenues:
Oil sales	$	174,427		$	101,511		$	337,152		$	166,485
Natural gas sales		41,283			25,821			90,558			46,849
Total operating revenues		215,710			127,332			427,710			213,334
Operating costs and expenses:
Oil and natural gas production		40,448			25,817			77,148			50,583
Exploration and abandonments		878			1,424			2,173			7,419
Depreciation, depletion and amortization		54,101			52,402			107,944			103,150
Accretion of discount on asset retirement obligations		372			301			772			579
Impairments of long-lived assets		4,692			4,499			7,312			8,555
General and administrative (including non-cash stock-based compensation of $2,871 and $2,188 for the three months ended June 30, 2010 and 2009, respectively, and $5,702 and $4,113 for the six months ended June 30, 2010 and 2009, respectively)		17,538			14,172			31,096			25,918
Bad debt expense		33			—			572			—
(Gain) loss on derivatives not designated as hedges		(112,763	)		81,606			(128,336	)		86,652
Total operating costs and expenses		5,299			180,221			98,681			282,856
Income (loss) from operations		210,411			(52,889	)		329,029			(69,522	)
Other income (expense):
Interest expense		(11,192	)		(6,200	)		(22,257	)		(10,570	)
Other, net		(304	)		180			(377	)		(148	)
Total other expense		(11,496	)		(6,020	)		(22,634	)		(10,718	)
Income (loss) before income taxes		198,915			(58,909	)		306,395			(80,240	)
Income tax benefit (expense)		(74,744	)		25,691			(114,684	)		33,797
Net income (loss)	$	124,171		$	(33,218	)	$	191,711		$	(46,443	)
Basic earnings per share:
Net income (loss) per share	$	1.36		$	(0.39	)	$	2.13		$	(0.55	)
Weighted average shares used in basic earnings per share		91,044			84,799			89,944			84,665
Diluted earnings per share:
Net income (loss) per share	$	1.35		$	(0.39	)	$	2.10		$	(0.55	)
Weighted average shares used in diluted earnings per share		92,297			84,799			91,220			84,665

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

2

Concho Resources Inc.
Consolidated Statement of Stockholders’ Equity
Unaudited

						Additional									Total
	Common Stock					Paid-in		Retained		Treasury Stock					Stockholders’
(in thousands)	Shares			Amount		Capital		Earnings		Shares		Amount			Equity
BALANCE AT DECEMBER 31, 2009		85,816		$	86	$	1,029,392	$	306,367		12	$	(417	)	$	1,335,428
Net income		—			—		—		191,711		—		—			191,711
Issuance of common stock		5,348			5		219,303		—		—		—			219,308
Stock options exercised		436			1		4,079		—		—		—			4,080
Stock-based compensation for restricted stock		—			—		4,114		—		—		—			4,114
Grants of restricted stock		254			—		—		—		—		—			—
Cancellation of restricted stock		(2	)		—		—		—		—		—			—
Stock-based compensation for stock options		—			—		1,588		—		—		—			1,588
Excess tax benefits related to stock-based compensation		—			—		6,703		—		—		—			6,703
Purchase of treasury stock		—			—		—		—		12		(585	)		(585	)
BALANCE AT JUNE 30, 2010		91,852		$	92	$	1,265,179	$	498,078		24	$	(1,002	)	$	1,762,347

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

3

Concho Resources Inc.
Consolidated Statements of Cash Flows
Unaudited

	Six Months Ended
	June 30,
(in thousands)	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	191,711		$	(46,443	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		107,944			103,150
Impairments of long-lived assets		7,312			8,555
Accretion of discount on asset retirement obligations		772			579
Exploration and abandonments, including dry holes		945			6,294
Non-cash compensation expense		5,702			4,113
Bad debt expense		572			—
Deferred income taxes		100,453			(39,799	)
(Gain) loss on sale of assets		(169	)		191
(Gain) loss on derivatives not designated as hedges		(128,336	)		86,652
Other non-cash items		2,420			1,686
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		(27,831	)		(18,401	)
Prepaid costs and other		105			612
Inventory		(3,834	)		(6,786	)
Accounts payable		(8,900	)		9,415
Revenue payable		(897	)		8,976
Other current liabilities		(8,439	)		(562	)
Net cash provided by operating activities		239,530			118,232
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and natural gas properties		(278,002	)		(223,283	)
Acquisition of oil and natural gas properties		(13,362	)		—
Additions to other property and equipment		(2,292	)		(2,014	)
Proceeds from the sale of oil and natural gas properties and other assets		790			1,004
Settlements received from (paid on) derivatives not designated as hedges		(9,299	)		61,465
Net cash used in investing activities		(302,165	)		(162,828	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		360,000			211,650
Payments of long-term debt		(562,000	)		(181,650	)
Net proceeds from issuance of common stock		219,308			—
Exercise of stock options		4,080			3,931
Excess tax benefit related to stock-based compensation		6,703			2,992
Payments for loan origination costs		(2,299	)		—
Purchase of treasury stock		(585	)		(192	)
Bank overdrafts		34,577			(6,806	)
Net cash provided by financing activities		59,784			29,925
Net decrease in cash and cash equivalents		(2,851	)		(14,671	)
Cash and cash equivalents at beginning of period		3,234			17,752
Cash and cash equivalents at end of period	$	383		$	3,081
SUPPLEMENTAL CASH FLOWS:
Cash paid for interest and fees, net of $56 and $18 capitalized interest	$	21,707		$	6,911
Cash paid for income taxes	$	16,715		$	4,232

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

4

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

Note A.Organization and nature of operations

     Concho Resources Inc. (the “Company” or “Concho”) is a Delaware corporation formed on February 22, 2006. The Company’s principal business is the acquisition, development and exploration of oil and natural gas properties in the Permian Basin region of Southeast New Mexico and West Texas.

Note B.Summary of significant accounting policies

     Principles of consolidation.The consolidated financial statements of the Company include the accounts of the Company and its wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated.

     Use of estimates in the preparation of financial statements.Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of derivative financial instruments, purchase price allocations for business and oil and natural gas property acquisitions and fair value of stock-based compensation.

     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, 2009 is derived from audited consolidated financial statements. In the opinion of management, the accompanying consolidated financial statements reflect all adjustments necessary to present fairly the Company’s financial position at June 30, 2010, its results of operations for the three and six months ended June 30, 2010 and 2009 and its cash flows for the six months ended June 30, 2010 and 2009. All such adjustments are of a normal recurring nature. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

     Certain disclosures have been condensed or omitted from these consolidated financial statements. Accordingly, these consolidated 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, 2009.

     Deferred loan costs.Deferred loan costs are stated at cost, net of amortization, which is computed using the effective interest and straight-line methods. The Company had deferred loan costs of $20.8 million and $20.7 million, net of accumulated amortization of $10.8 million and $8.6 million, at June 30, 2010 and December 31, 2009, respectively.

5

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     Future amortization expense of deferred loan costs at June 30, 2010 is as follows:

(in thousands)
Remaining 2010	$	2,458
2011		4,973
2012		5,057
2013		3,433
2014		1,132
Thereafter		3,718
Total	$	20,771

     Intangible assets.The Company has capitalized certain operating rights acquired in 2008. The gross operating rights, which have no residual value, are amortized over the estimated economic life of approximately 25 years. Impairment will be assessed if indicators of potential impairment exist or when there is a material change in the remaining useful economic life. The following table reflects the gross and net intangible assets at June 30, 2010 and December 31, 2009:

	June 30,			December 31,
(in thousands)	2010			2009
Gross intangible — operating rights	$	38,717		$	38,717
Accumulated amortization		(2,969	)		(2,195	)
Net intangible — operating rights	$	35,748		$	36,522

     The following table reflects amortization expense for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2010		2009		2010		2009
Amortization expense	$	387	$	388	$	774	$	781

6

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     The following table reflects the estimated aggregate amortization expense for each of the periods presented below at June 30, 2010:

(in thousands)
Remaining 2010	$	774
2011		1,549
2012		1,549
2013		1,549
2014		1,549
Thereafter		28,778
Total	$	35,748

     Oil and natural gas sales and imbalances.Oil and natural 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 natural gas sales, recognizing revenues based on the Company’s share of actual proceeds from the oil and natural gas sold to purchasers. Oil and natural 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 from or payable to the other owners unless the imbalance has reached a level at which 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.

     The following tables reflect the Company’s natural gas imbalance positions at June 30, 2010 and December 31, 2009 as well as amounts reflected in oil and natural gas production expense for the three and six months ended June 30, 2010 and 2009:

	June 30,		December 31,
(dollars in thousands)	2010		2009
Natural gas imbalance receivable (included in other assets)	$	431	$	444
Undertake position (Mcf)		95,736		98,584
Natural gas imbalance liability (included in asset retirement obligations and other long-term liabilities)	$	525	$	533
Overtake position (Mcf)		99,438		101,278

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(dollars in thousands)	2010		2009		2010		2009
Value of net overtake (undertake) arising during the period increasing (decreasing) oil and natural gas production expense	$	10	$	9	$	5	$	(40	)
Net overtake (undertake) position arising during the period (Mcf)		2,292		1,697		1,008		(10,069	)

     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.

     General and administrative expense.The Company receives fees for the operation of jointly owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $3.6 million

7

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

and $2.8 million for the three months ended June 30, 2010 and 2009, respectively, and $6.5 million and $5.4 million for the six months ended June 30, 2010 and 2009, respectively.

     Recent accounting pronouncements.

     Various topics.In February 2010, the Financial Accounting Standards Board (the “FASB”) issued an update to various topics, which eliminated outdated provisions and inconsistencies in the Accounting Standards Codification (the “Codification”), and clarified certain guidance to reflect the FASB’s original intent. The update is effective for the first reporting period, including interim periods, beginning after issuance of the update, except for the amendments affecting embedded derivatives and reorganizations. In addition to amending the Codification, the FASB made corresponding changes to the legacy accounting literature to facilitate historical research. These changes are included in an appendix to the update. The Company adopted the update effective January 1, 2010, and the adoption did not have a significant impact on the Company’s consolidated financial statements.

     Accounting for extractive activities.In April 2010, the FASB issued an amendment to a paragraph in the accounting standard for oil and natural gas extractive activities accounting. The standard adds to the Codification the SEC’sModernization of Oil and Gas Reportingrelease. The Company adopted the update effective April 20, 2010, and the adoption did not have a significant impact on the Company’s consolidated financial statements.

Note C.Exploratory well costs

     The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are presented in unproved properties in the consolidated balance sheets. If the exploratory well is determined to be impaired, the well costs are charged to expense.

     The following table reflects the Company’s capitalized exploratory well activity during the three and six months ended June 30, 2010:

	Three Months Ended			Six Months Ended
(in thousands)	June 30, 2010			June 30, 2010
Beginning capitalized exploratory well costs	$	24,317		$	8,668
Additions to exploratory well costs pending the determination of proved reserves		34,161			64,496
Reclassifications due to determination of proved reserves		(25,616	)		(40,302	)
Exploratory well costs charged to expense		—			—
Ending capitalized exploratory well costs	$	32,862		$	32,862

8

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     The following table provides an aging, at June 30, 2010 and December 31, 2009, of capitalized exploratory well costs based on the date drilling was completed:

	June 30,		December 31,
(in thousands)	2010		2009
Wells in drilling progress	$	7,903	$	1,767
Capitalized exploratory well costs that have been capitalized for a period of one year or less		24,959		6,901
Capitalized exploratory well costs that have been capitalized for a period greater than one year		—		—
Total capitalized exploratory well costs	$	32,862	$	8,668

     At June 30, 2010, the Company had 45 gross exploratory wells waiting on their completion, including 21 wells in the Texas Permian area, 18 wells in the New Mexico Permian area and 6 wells in the emerging plays area.

Note D.Business Combinations

     Wolfberry acquisitions.In December 2009, together with the acquisition of related additional interests that closed in 2010, the Company closed two acquisitions (the “Wolfberry Acquisitions”) of interests in producing and non-producing assets in the Wolfberry play in the Permian Basin for approximately $270.7 million. The Wolfberry Acquisitions were primarily funded with borrowings under the Company’s credit facility. See Note J. The Company’s 2009 results of operations do not include any production, revenues or costs from the Wolfberry Acquisitions.

     The following table represents the allocation of the total purchase price of the Wolfberry Acquisitions to the acquired assets and liabilities. The allocation represents the fair values assigned to each of the assets acquired and liabilities assumed:

(in thousands)
Fair value of the Wolfberry Acquisitions’ net assets:
Proved oil and natural gas properties	$	212,987
Unproved oil and natural gas properties		58,222
Total assets acquired		271,209
Asset retirement obligations		(464	)
Net purchase price	$	270,745

Note E.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 productive 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.

9

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     The following table summarizes the Company’s asset retirement obligation transactions recorded during the three and six months ended June 30, 2010 and 2009:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2010			2009			2010			2009
Asset retirement obligations, beginning of period	$	20,837		$	18,254		$	22,754		$	16,809
Liabilities incurred from new wells		665			102			1,111			270
Accretion expense		372			301			772			579
Disposition of wells		—			—			—			(142	)
Liabilities settled upon plugging and abandoning wells		(112	)		(343	)		(297	)		(353	)
Revision of estimates		295			(3,928	)		(2,283	)		(2,777	)
Asset retirement obligations, end of period	$	22,057		$	14,386		$	22,057		$	14,386

Note F.Stockholders’ equity

     Equity issuance.On February 1, 2010, the Company issued 5,347,500 shares of its common stock at $42.75 per share. After deducting underwriting discounts of approximately $9.1 million and transaction costs, the Company received net proceeds of approximately $219.3 million. The net proceeds from this offering were used to repay a portion of the borrowings under the Company’s credit facility.

     Treasury stock.The restrictions on certain restricted stock awards issued to certain of the Company’s officers, directors and key employees lapsed during the six months ended June 30, 2010. Immediately upon the lapse of restrictions, these individuals became liable for 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, some of such persons elected to deliver shares of the Company’s common stock to the Company in exchange for cash used to satisfy such tax liability. In total, at June 30, 2010 and December 31, 2009, the Company had acquired 23,667 and 12,380 shares, respectively, that are held as treasury stock in the approximate amounts of $1.0 million and $0.4 million, respectively.

Note G.Incentive plans

     Defined contribution plan.The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees and maintains certain other acquired plans. Currently, the Company matches 100 percent of employee contributions, not to exceed 6 percent of the employee’s annual salary. The Company contributions to the plans for the three months ended June 30, 2010 and 2009, were approximately $0.4 million and $0.2 million, respectively, and approximately $0.6 million and $0.5 million for the six months ended June 30, 2010 and 2009, respectively.

10

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     Stock incentive plan.The Company’s 2006 Stock Incentive Plan (together with applicable stock 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. The following table shows the number of existing awards and awards available under the Plan at June 30, 2010:

	Number of
	Common Shares
Approved and authorized awards		5,850,000
Stock option grants, net of forfeitures		(3,463,720	)
Restricted stock grants, net of forfeitures		(1,057,465	)
Awards available for future grant		1,328,815

     Restricted stock awards.All restricted shares are treated as issued and outstanding in the accompanying consolidated balance sheets. Holders of restricted stock are eligible to vote and receive dividends, if any. If an employee terminates employment prior the restriction lapse date, the awarded shares that have not vested as of the date of termination of employment are forfeited and cancelled and are no longer considered issued and outstanding. A summary of the Company’s restricted stock awards activity under the Plan for the six months ended June 30, 2010 is presented below:

	Number of			Grant Date
	Restricted			Fair Value
	Shares			Per Share
Restricted stock:
Outstanding at December 31, 2009		497,257
Shares granted		254,130		$	48.57
Shares cancelled / forteited		(1,719	)
Lapse of restrictions		(65,435	)
Outstanding at June 30, 2010		684,233

11

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     The following table summarizes information about stock-based compensation for the Company’s restricted stock awards for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2010		2009		2010			2009
Grant date fair value for awards during the period:
Employee grants	$	5,751	$	4,620	$	7,341	(a)	$	4,620
Officer and director grants		—		—		5,075			1,850
Total	$	5,751	$	4,620	$	12,416		$	6,470
Stock-based compensation expense from restricted stock:
Employee grants	$	1,140	$	830	$	2,118		$	1,393
Officer and director grants		1,152		473		1,996			807
Total	$	2,292	$	1,303	$	4,114		$	2,200
Income taxes and other information:
Income tax benefit related to restricted stock	$	864	$	586	$	1,553		$	927
Deductions in current taxable income related to restricted stock	$	1,252	$	3,989	$	2,959		$	4,367

(a) Includes effects of modifications to certain stock-based awards.

     Stock option awards.A summary of the Company’s stock option awards activity under the Plan for the six months ended June 30, 2010 is presented below:

				Weighted
				Average
	Number of			Exercise
	Options			Price
Stock options:
Outstanding at December 31, 2009		2,156,503		$	14.11
Options granted		—		$	—
Options exercised		(435,853	)	$	9.36
Outstanding at June 30, 2010		1,720,650		$	15.31
Vested at end of period		1,247,705		$	13.26
Exercisable at end of period		835,489		$	15.77

12

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     The following table summarizes information about the Company’s vested and exercisable stock options outstanding at June 30, 2010:

				Weighted
				Average	Weighted
		Number		Remaining	Average
		of Stock		Contractual	Exercise		Intrinsic
		Options		Life	Price		Value
							(in thousands)
Vested options:
June 30, 2010:
Exercise price	$8.00		607,782	1.93 years	$	8.00	$	28,766
Exercise price	$12.00		95,887	4.46 years	$	12.00		4,155
Exercise price	$12.50 - $15.50		257,500	6.22 years	$	14.83		10,429
Exercise price	$20.00 - $23.00		236,578	7.80 years	$	21.67		7,962
Exercise price	$28.00 - $37.27		49,958	7.97 years	$	31.78		1,177
			1,247,705	4.37 years	$	13.26	$	52,489
Exercisable options:
June 30, 2010:
Exercise price	$8.00		213,394	2.74 years	$	8.00	$	10,100
Exercise price	$12.00		78,059	5.13 years	$	12.00		3,382
Exercise price	$12.50 - $15.50		257,500	6.22 years	$	14.83		10,429
Exercise price	$20.00 - $23.00		236,578	7.80 years	$	21.67		7,962
Exercise price	$28.00 - $37.27		49,958	7.97 years	$	31.78		1,177
			835,489	5.78 years	$	15.77	$	33,050

13

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     The following table summarizes information about stock-based compensation for stock options for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2010		2009		2010		2009
Grant date fair value for awards during the period:
Employee grants	$	—	$	—	$	—	$	—
Officer and director grants		—		—		—		1,454
Total	$	—	$	—	$	—	$	1,454
Stock-based compensation expense from stock options:
Employee grants	$	42	$	70	$	86	$	141
Officer and director grants		537		815		1,502		1,772
Total	$	579	$	885	$	1,588	$	1,913
Income taxes and other information:
Income tax benefit related to stock options	$	218	$	415	$	599	$	806
Deductions in current taxable income related to stock options exercised	$	8,473	$	4,117		$18,124	$	7,157

     The Company used the simplified method that is accepted by the SEC to calculate the expected term for stock options granted during the six months ended June 30, 2009, since it did 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.

     Future stock-based compensation expense.Future stock-based compensation expense based on the awards outstanding at June 30, 2010 is summarized in the table below:

	Restricted		Stock
(in thousands)	Stock		Options		Total
Remaining 2010	$	4,862	$	1,065	$	5,927
2011		6,239		879		7,118
2012		3,524		184		3,708
2013		1,237		15		1,252
2014		56		—		56
Total	$	15,918	$	2,143	$	18,061

14

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

Note H.Disclosures about fair value of financial instruments

     The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

Level 1:	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be 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 the Company values 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, basis swaps, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company utilizes its counterparties’ valuations to assess the reasonableness of its 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 commodity price collars and floors, as well as investments. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although the Company utilizes its counterparties’ valuations to assess the reasonableness of its prices and valuation techniques, the Company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.

15

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis at June 30, 2010, for each of the fair value hierarchy levels:

	Fair Value Measurements at Reporting Date Using
			Significant
	Quoted Prices in		Other			Significant
	Active Markets for		Observable			Unobservable		Fair Value at
	Identical Assets		Inputs			Inputs		June 30,
(in thousands)	(Level 1)		(Level 2)			(Level 3)		2010
Assets:
Commodity derivative price swap contracts	$	—	$	122,689		$	—	$	122,689
Commodity derivative price collar contracts		—		—			3,808		3,808
		—		122,689			3,808		126,497
Liabilities:
Commodity derivative price swap contracts		—		(44,315	)		—		(44,315	)
Commodity derivative basis swap contracts		—		(5,095	)		—		(5,095	)
Interest rate derivative swap contracts		—		(6,285	)		—		(6,285	)
		—		(55,695	)		—		(55,695	)
Net financial assets (liabilities)	$	—	$	66,994		$	3,808	$	70,802

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

(in thousands)
Balance at December 31, 2009	$	(945	)
Realized and unrealized gains, net		6,584
Settlements (receipts), net		(1,831	)
Balance at June 30, 2010	$	3,808
Total gains for the period included in earnings attributable to the change in unrealized gains relating to assets (liabilities) still held at the reporting date	$	4,753

16

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

Assets and Liabilities Measured at Fair Value on a Recurring Basis

     The following table presents the carrying amounts and fair values of the Company’s financial instruments at June 30, 2010 and December 31, 2009:

	June 30, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
(in thousands)	Value		Value		Value		Value
Assets:
Derivative instruments	$	94,573	$	94,573	$	24,923	$	24,923
Liabilities:
Derivative instruments	$	23,771	$	23,771	$	91,756	$	91,756
Credit facility	$	348,000	$	332,029	$	550,000	$	528,849
8.625% senior notes due 2017	$	296,023	$	309,000	$	295,836	$	315,000

     Cash and cash equivalents, accounts receivable, other current assets, accounts payable, interest payable and other current liabilities.The carrying amounts approximate fair value due to the short maturity of these instruments.

     Credit facility.The fair value of the Company’s credit facility is estimated by discounting the principal and interest payments at the Company’s credit adjusted discount rate at the reporting date.

     Senior notes.The fair value of the Company’s senior notes is based on quoted market prices.

17

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     Derivative instruments.The fair value of the Company’s derivative instruments are estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. 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 tables (i) summarize the valuation of each of the Company’s financial instruments by required pricing levels and (ii) summarize the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at June 30, 2010 and December 31, 2009:

	Fair Value Measurements Using
			Significant					Total
	Quoted Prices in		Other			Significant		Carrying Value
	Active Markets for		Observable			Unobservable		at
	Identical Assets		Inputs			Inputs		June 30,
(in thousands)	(Level 1)		(Level 2)			(Level 3)		2010
Assets(1)
Current:(a)
Commodity derivative price swap contracts	$	—	$	50,851		$	—	$	50,851
Commodity derivative price collar contracts		—		—			3,808		3,808
		—		50,851			3,808		54,659
Noncurrent:(b)
Commodity derivative price swap contracts		—		71,838			—		71,838
Interest rate derivative swap contracts		—		—			—		—
		—		71,838			—		71,838
Liabilities(1)
Current:(a)
Commodity derivative price swap contracts		—		(32,772	)		—		(32,772	)
Commodity derivative basis swap contracts		—		(3,485	)		—		(3,485	)
Interest rate derivative swap contracts		—		(4,086	)		—		(4,086	)
		—		(40,343	)		—		(40,343	)
Noncurrent:(b)
Commodity derivative price swap contracts		—		(11,543	)		—		(11,543	)
Commodity derivative basis swap contracts		—		(1,610	)		—		(1,610	)
Interest rate derivative swap contracts		—		(2,199	)		—		(2,199	)
		—		(15,352	)		—		(15,352	)
Net financial assets	$	—	$	66,994		$	3,808	$	70,802
(a)Total current financial assets, gross basis								$	14,316
(b)Total noncurrent financial assets, gross basis									56,486
Net financial assets								$	70,802

18

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

	Fair Value Measurements Using
			Significant						Total
	Quoted Prices in		Other			Significant			Carrying Value
	Active Markets for		Observable			Unobservable			at
	Identical Assets		Inputs			Inputs			December 31,
(in thousands)	(Level 1)		(Level 2)			(Level 3)			2009
Assets(1)
Current:(a)
Commodity derivative price swap contracts	$	—	$	13,850		$	—		$	13,850
Commodity derivative price collar contracts		—		—			134			134
		—		13,850			134			13,984
Noncurrent:(b)
Commodity derivative price swap contracts		—		35,016			—			35,016
Interest rate derivative swap contracts		—		1,369			—			1,369
		—		36,385			—			36,385
Liabilities(1)
Current:(a)
Commodity derivative price swap contracts		—		(65,351	)		—			(65,351	)
Commodity derivative basis swap contracts		—		(5,254	)		—			(5,254	)
Interest rate derivative swap contracts		—		(3,870	)		—			(3,870	)
Commodity derivative price collar contracts		—		—			(619	)		(619	)
		—		(74,475	)		(619	)		(75,094	)
Noncurrent:(b)
Commodity derivative price swap contracts		—		(38,259	)		—			(38,259	)
Commodity derivative basis swap contracts		—		(3,389	)		—			(3,389	)
Commodity derivative price collar contracts		—		—			(460	)		(460	)
		—		(41,648	)		(460	)		(42,108	)
Net financial liabilities	$	—	$	(65,888	)	$	(945	)	$	(66,833	)
(a)Total current financial liabilities, gross basis									$	(61,110	)
(b)Total noncurrent financial liabilities, gross basis										(5,723	)
Net financial liabilities									$	(66,833	)

(1) The fair value of derivative instruments reported in the Company’s consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table reports the net basis derivative fair values as reported in the consolidated balance sheets at June 30, 2010 and December 31, 2009:

19

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

	June 30,			December 31,
(in thousands)	2010			2009
Consolidated Balance Sheet Classification:
Current derivative contracts:
Assets	$	32,409		$	1,309
Liabilities		(18,093	)		(62,419	)
Net current	$	14,316		$	(61,110	)
Noncurrent derivative contracts:
Assets	$	62,164		$	23,614
Liabilities		(5,678	)		(29,337	)
Net noncurrent	$	56,486		$	(5,723	)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

     Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

     Impairments of long-lived assets —The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In that circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by amortization base or by individual well for those wells not constituting part of an amortization base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs.

     The Company periodically reviews its proved oil and natural gas properties that are sensitive to oil and natural gas prices for impairment. Due primarily to downward adjustments to the economically recoverable resource potential associated with declines in commodity prices and well performance, the Company recognized impairment expense related to its proved oil and natural gas properties. The following table reports the carrying amounts, estimated fair values and impairment expense of long-lived assets for the three and six months ended June 30, 2010 and 2009:

	Carrying		Estimated		Impairment
(in thousands)	Amount		Fair Value		Expense
Three Months Ended June 30, 2010	$	7,884	$	3,192	$	4,692
Three Months Ended June 30, 2009	$	7,232	$	2,733	$	4,499
Six Months Ended June 30, 2010	$	13,776	$	6,464	$	7,312
Six Months Ended June 30, 2009	$	14,175	$	5,620	$	8,555

20

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     Asset Retirement Obligations —The Company estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note E for a summary of changes in asset retirement obligations.

     Measurement information for assets that are measured at fair value on a nonrecurring basis was as follows:

	Fair Value Measurements Using
			Significant
	Quoted Prices in		Other		Significant
	Active Markets for		Observable		Unobservable		Total
	Identical Assets		Inputs		Inputs		Impairment
(in thousands)	(Level 1)		(Level 2)		(Level 3)		Loss
Three Months Ended June 30, 2010:
Impairment of long-lived assets	$	—	$	—	$	3,192	$	4,692
Asset retirement obligations incurred in current period		—		—		665
Three Months Ended June 30, 2009:
Impairment of long-lived assets	$	—	$	—	$	2,733	$	4,499
Asset retirement obligations incurred in current period		—		—		102
Six Months Ended June 30, 2010:
Impairment of long-lived assets	$	—	$	—	$	6,464	$	7,312
Asset retirement obligations incurred in current period		—		—		1,111
Six Months Ended June 30, 2009:
Impairment of long-lived assets	$	—	$	—	$	5,620	$	8,555
Asset retirement obligations incurred in current period		—		—		270

Note I.Derivative financial instruments

     The Company uses derivative financial contracts to manage exposures to commodity price and interest rate fluctuations. Commodity hedges are used to (i) reduce the effect of the volatility of price changes on the oil and natural gas the Company produces and sells, (ii) support the Company’s capital budget and expenditure plans and (iii) support the economics associated with acquisitions. Interest rate hedges are used to mitigate the cash flow risk associated with rising interest rates. The Company does not enter into derivative financial instruments for speculative or trading purposes. The Company also may enter into physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated financial statements.

     Currently, the Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its statements of operations.

21

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     New commodity derivative contracts in the first half of 2010.During the six months ended June 30, 2010, the Company entered into additional commodity derivative contracts to hedge a portion of its estimated future production. The following table summarizes information about these additional commodity derivative contracts:

	Aggregate		Index			Contract
	Volume		Price			Period
Oil (volumes in Bbls):
Price swap		670,000	$	83.72	(a)		1/1/10 - 12/31/10
Price swap		195,000	$	76.85	(a)		3/1/10 - 12/31/10
Price swap		1,463,000	$	88.63	(a)		5/1/10 - 12/31/10
Price swap		2,136,000	$	88.36	(a)		1/1/11 - 12/31/11
Price swap		2,268,000	$	92.68	(a)		1/1/12 - 12/31/12
Natural gas (volumes in MMBtus):
Price swap		418,000	$	5.99	(b)		2/1/10 - 12/31/10
Price swap		1,250,000	$	5.55	(b)		3/1/10 - 12/31/10
Price swap		5,076,000	$	6.14	(b)		1/1/11 - 12/31/11
Price swap		300,000	$	6.54	(b)		1/1/12 - 12/31/12

(a)	The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly average futures price.
(b)	The index prices for the natural gas price swaps are based on the NYMEX-Henry Hub last trading day futures price.

22

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     Commodity derivative contracts at June 30, 2010.The following table sets forth the Company’s outstanding commodity derivative contracts at June 30, 2010:

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps:(a)
2010:
Volume (Bbl)						1,817,936		1,651,936		3,469,872
Price per Bbl					$	76.78	$	76.43	$	76.61
2011:
Volume (Bbl)		1,378,436		1,339,436		1,304,436		1,272,436		5,294,744
Price per Bbl	$	81.55	$	81.80	$	82.03	$	82.26	$	81.90
2012:
Volume (Bbl)		693,000		693,000		693,000		693,000		2,772,000
Price per Bbl	$	99.07	$	99.07	$	99.07	$	99.07	$	99.07
Natural Gas Swaps:(b)
2010:
Volume (MMBtu)						2,427,000		2,258,000		4,685,000
Price per MMBtu					$	6.03	$	6.03	$	6.03
2011:
Volume (MMBtu)		1,569,000		3,069,000		3,069,000		3,069,000		10,776,000
Price per MMBtu	$	6.36	$	6.62	$	6.62	$	6.62	$	6.58
2012:
Volume (MMBtu)		75,000		75,000		75,000		75,000		300,000
Price per MMBtu	$	6.54	$	6.54	$	6.54	$	6.54	$	6.54
Natural Gas Collars:(b)
2010:
Volume (MMBtu)						1,500,000		1,500,000		3,000,000
Price per MMBtu					$	5.25 - $5.75	$	6.00 - $6.80	$	5.63 - $6.28
2011:
Volume (MMBtu)		1,500,000		—		—		—		1,500,000
Price per MMBtu	$	6.00 - $6.80		—		—		—	$	6.00 - $6.80
Natural Gas Basis Swaps:(c)
2010:
Volume (MMBtu)						2,100,000		2,100,000		4,200,000
Price per MMBtu					$	0.85	$	0.85	$	0.85
2011:
Volume (MMBtu)		1,800,000		1,800,000		1,800,000		1,800,000		7,200,000
Price per MMBtu	$	0.87	$	0.76	$	0.76	$	0.76	$	0.79

(a)	The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly average futures price.
(b)	The index prices for the natural gas price swaps and collars are based on the NYMEX-Henry Hub last trading day futures price.
(c)	The basis differential between the El Paso Permian delivery point and NYMEX Henry Hub delivery point.

23

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     Interest rate derivative contracts.The Company has an interest rate swap which fixes the LIBOR interest rate on $300 million of the Company’s bank debt at 1.90 percent for three years beginning in May 2009. For this portion of the Company’s bank debt, the all-in interest rate will be calculated by adding the fixed rate of 1.90 percent to a margin that ranges from 2.00 percent to 3.00 percent, depending on the amount of bank debt outstanding.

     The following table summarizes the gains and losses reported in earnings related to the commodity and interest rate derivative instruments for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2010			2009			2010			2009
Gain (loss) on derivatives not designated as hedges:
Cash (payments on) receipts from derivatives not designated as hedges:
Commodity derivatives:
Oil	$	(2,852	)	$	21,828		$	(12,985	)	$	56,412
Natural gas		5,614			3,292			6,120			5,832
Interest rate derivatives		(1,221	)		(779	)		(2,434	)		(779	)
Mark-to-market gain (loss):
Commodity derivatives:
Oil		119,303			(105,062	)		120,741			(144,099	)
Natural gas		(6,509	)		(4,312	)		20,678			(5,018	)
Interest rate derivatives		(1,572	)		3,427			(3,784	)		1,000
Total gain (loss) on derivatives not designated as hedges	$	112,763		$	(81,606	)	$	128,336		$	(86,652	)

     All of the Company’s commodity derivative contracts at June 30, 2010 are expected to settle by December 31, 2012.

Note J.Debt

     The Company’s debt consisted of the following at June 30, 2010 and December 31, 2009:

	June 30,			December 31,
(in thousands)	2010			2009
Credit facility	$	348,000		$	550,000
8.625% unsecured senior notes due 2017		300,000			300,000
Less: unamortized original issue discount		(3,977	)		(4,164	)
Less: current portion		—			—
Total long-term debt	$	644,023		$	845,836

     Credit facility.The Company’s credit facility, as amended (the “Credit Facility”), has a maturity date of July 31, 2013. At June 30, 2010, the Company’s borrowing base was $1.2 billion, it had letters of credit outstanding under the Credit Facility of approximately $25,000, and its availability to borrow additional funds was approximately $852.0 million. The next scheduled borrowing base redetermination will occur in October 2010. Between scheduled borrowing base redeterminations, the Company and, if requested by 66 2/3 percent of the lenders, the lenders may each request one special redetermination.

24

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     In July 2010, the Company received an $800 million underwritten commitment from two of its lenders under the Credit Facility to expand the size of its existing Credit Facility from $1.2 billion to $2.0 billion as part of the financing for an upcoming acquisition. The expanded credit facility is expected to close simultaneously with such acquisition. See Note Q.

     Advances on the Credit Facility bear interest, at the Company’s option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) (3.25 percent at June 30, 2010) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). At June 30, 2010, the interest rates of Eurodollar rate advances and JPM Prime Rate advances vary, with interest margins ranging from 200 to 300 basis points and 112.5 to 212.5 basis points, respectively, per annum depending on the debt balance outstanding. At June 30, 2010, the Company pays commitment fees on the unused portion of the available borrowing base of 50 basis points per annum.

     The Credit Facility also includes a same-day advance facility under which the Company may borrow funds from the administrative agent. Same-day advances cannot exceed $25 million and the maturity dates cannot exceed fourteen days. The interest rate on the same-day advance facility is the JPM Prime Rate plus the applicable interest margin.

     The Company’s obligations under the Credit Facility are secured by a first lien on substantially all of the Company’s oil and natural gas properties. In addition, all of the Company’s subsidiaries are guarantors and all general partner, limited partner and membership interests in the Company’s subsidiaries owned by the Company have been pledged to secure borrowings under the Credit Facility. The Credit Facility contains various restrictive covenants and compliance requirements which include (a) maintenance of certain financial ratios, including (i) 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 to be no greater than 4.0 to 1.0, and (ii) a ratio of current assets to current liabilities, excluding noncash assets and liabilities related to financial derivatives and asset retirement obligations and including the unfunded amounts under the Credit Facility, 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 mergers, combinations and dispositions of assets; and (d) restrictions on the payment of cash dividends. At June 30, 2010, the Company was in compliance with its covenants under the Credit Facility.

     8.625% unsecured senior notes.On September 18, 2009, the Company completed its public offering of $300 million aggregate principal amount of 8.625% senior notes due 2017 (the “Senior Notes”). The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries.

     The Senior Notes will mature on October 1, 2017, and interest is payable on the Senior Notes each April 1 and October 1. The Company received net proceeds of $288.2 million (net of related estimated offering costs), which were used to repay a portion of the outstanding borrowings under the Credit Facility.

     The Company may redeem some or all of the Senior Notes at any time on or after October 1, 2013 at the redemption prices specified in the indenture governing the Senior Notes. The Company may also redeem up to 35 percent of the Senior Notes using all or a portion of the net proceeds of certain public sales of equity interests completed before October 1, 2012 at a redemption price as specified in the indenture. If the Company sells certain assets or experiences specific kinds of change of control, each as described in the indenture, each holder of the Senior Notes will have the right to require the Company to repurchase the Senior Notes at a purchase price described in the indenture plus accrued and unpaid interest, if any, to the date of repurchase. At June 30, 2010, the Company was in compliance with its covenants in the indenture governing the Senior Notes.

25

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     Future interest expense from the original issue discount on the Senior Notes at June 30, 2010 is as follows:

(in thousands)
Remaining 2010	$	197
2011		421
2012		462
2013		507
2014		557
Thereafter		1,833
Total	$	3,977

     Principal maturities of debt.Principal maturities of debt outstanding at June 30, 2010 are as follows:

(in thousands)
2010	$	—
2011		—
2012		—
2013		348,000
2014 and thereafter		300,000
Total	$	648,000

     Interest expense.The following amounts have been incurred and charged to interest expense for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2010			2009			2010			2009
Cash payments for interest	$	18,016		$	3,457		$	21,763		$	6,929
Amortization of original issue discount		95			—			187			—
Amortization of deferred loan origination costs		1,164			857			2,204			1,713
Net changes in accruals		(8,045	)		1,889			(1,841	)		1,946
Interest costs incurred		11,230			6,203			22,313			10,588
Less: capitalized interest		(38	)		(3	)		(56	)		(18	)
Total interest expense	$	11,192		$	6,200		$	22,257		$	10,570

26

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

Note K.Commitments and contingencies

     Severance agreements.The Company has entered into severance and change in control agreements with all of its officers. The current annual salaries for the Company’s officers covered under such agreements total approximately $2.1 million.

     Indemnification.The Company has agreed to indemnify its directors and officers for claims and damages arising from certain acts or omissions taken in such capacity.

     Legal actions.The Company is a party to proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to any such proceedings or claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future results of operations. The Company will continue to evaluate proceedings and claims involving the Company on a quarter-by-quarter basis and will establish and adjust any reserves as appropriate to reflect its assessment of the then current status of the matters.

     Acquisition commitments.In connection with the July 2008 acquisition of Henry Petroleum LP and certain entities and individuals affiliated with Henry Petroleum LP (collectively, the “Henry Entities”), the Company agreed to pay certain employees, who were formerly employed by the Henry Entities, bonuses of approximately $11.0 million in the aggregate at each of the first and second anniversaries of the closing of the acquisition. Except as described below, these employees must remain employed with the Company to receive the bonus. A former Henry Entities employee who is otherwise entitled to a full bonus will receive the full bonus (i) if the Company terminates the employee without cause, (ii) upon the death or disability of such employee or (iii) upon a change in control of the Company. If any such employee resigns or is terminated for cause, the employee will not receive the bonus and, subject to certain conditions, the Company will be required to reimburse the sellers in the acquisition of the Henry Entities 65 percent of the bonus amount not paid to the employee. The Company reflects the bonus amounts to be paid to these employees as a period cost, which is included in the Company’s results of operations over the period earned. Amounts that ultimately are determined to be paid to the sellers are treated as a “contingent purchase price” and reflected as an adjustment to the purchase price. During the three months ended June 30, 2010 and 2009, the Company recognized $2.5 million and $2.8 million, respectively, of this obligation in its results of operations, and $4.9 million and $5.3 million during the six months ended June 30, 2010 and 2009, respectively.

     Daywork commitments.The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future, including agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments in the periods in which well capital is incurred or rig services are provided. The following table summarizes the Company’s future drilling commitments at June 30, 2010:

	Payments Due By Period
			Less than		1 - 3		3 - 5		More than
(in thousands)	Total		1 year		years		years		5 years
Daywork drilling contracts with related parties(a)	$	1,000	$	1,000	$	—	$	—	$	—
Daywork drilling contracts assumed in the Henry Entities acquisition(b)		313		313		—		—		—
Total contractual drilling commitments	$	1,313	$	1,313	$	—	$	—	$	—

(a)	Consists of daywork drilling contracts with Silver Oak Drilling, LLC, an affiliate of Chase Oil Corporation, a stockholder of the Company.
(b)	A major oil and natural gas company which owns an interest in the wells being drilled and the Company are parties to these contracts. Only the Company’s 25 percent share of the contract obligation has been reflected above.

27

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     Operating leases.The Company leases vehicles, equipment and office facilities under non-cancellable operating leases. Lease payments associated with these operating leases for the three months ended June 30, 2010 and 2009 were approximately $0.5 million and $0.6 million, respectively, and approximately $1.1 million and $1.3 million for the six months ended June 30, 2010 and 2009, respectively. Future minimum lease commitments under non-cancellable operating leases at June 30, 2010 are as follows:

(in thousands)
Remaining 2010	$	1,165
2011		1,885
2012		1,452
2013		1,324
2014 and thereafter		3,982
Total	$	9,808

Note L.Income taxes

     The Company uses an asset and liability approach for financial accounting and reporting for income taxes. The Company’s objectives of accounting for income taxes are to recognize (i) the amount of taxes payable or refundable for the current year and (ii) deferred tax liabilities and assets for the future tax consequences of events that have been recognized in its financial statements or tax returns. The Company and its subsidiaries file a federal corporate income tax return on a consolidated basis. The tax returns and the amount of taxable income or loss are subject to examination by federal and state taxing authorities.

     The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Management monitors Company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net operating loss carryforwards (“NOLs”) and other deferred tax attributes in the United States, state, and local tax jurisdictions will be utilized prior to their expiration. At June 30, 2010, the Company had no valuation allowances related to its deferred tax assets.

     At June 30, 2010, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2004 through 2009 remain subject to examination by the major tax jurisdictions.

28

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     Income tax provision.The Company’s income tax provision (benefit) and amounts separately allocated were attributable to the following items for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2010			2009			2010			2009
Tax expense (benefit) related to income (loss) from operations	$	74,744		$	(25,691	)	$	114,684		$	(33,797	)
Changes in stockholders’ equity:
Excess tax benefits related to stock-based compensation		(3,205	)		(2,188	)		(6,703	)		(2,992	)
	$	71,539		$	(27,879	)	$	107,981		$	(36,789	)

     The Company’s income tax provision (benefit) attributable to income (loss) from operations consisted of the following for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(in thousands)	2010		2009			2010		2009
Current:
U.S. federal	$	1,628	$	2,856		$	12,506	$	5,294
U.S. state and local		492		381			1,725		708
		2,120		3,237			14,231		6,002
Deferred:
U.S. federal		64,911		(25,518	)		89,592		(35,103	)
U.S. state and local		7,713		(3,410	)		10,861		(4,696	)
		72,624		(28,928	)		100,453		(39,799	)
	$	74,744	$	(25,691	)	$	114,684	$	(33,797	)

29

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     The Company’s provision for income taxes differed from the U.S. federal statutory rate of 35 percent primarily due to state income taxes and non-deductible expenses. The reconciliation between the tax expense computed by multiplying pretax income by the U.S. federal statutory rate and the reported amounts of income tax expense is as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2010			2009			2010			2009
Income (loss) at U.S. federal statutory rate	$	69,620		$	(20,618	)	$	107,238		$	(28,084	)
State income taxes (net of federal tax effect)		5,333			(1,969	)		8,181			(2,592	)
Statutory depletion		45			—			(178	)		—
Nondeductible expense & other		(254	)		(3,104	)		(557	)		(3,121	)
Income tax expense (benefit)	$	74,744		$	(25,691	)	$	114,684		$	(33,797	)
Effective tax rate		37.6	%		43.6	%		37.4	%		42.1	%

Note M.Related parties

     The following tables summarize charges incurred with and payments made to the Company’s related parties and reported in the consolidated statements of operations, as well as outstanding payables and receivables included in the consolidated balance sheets for the periods presented:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2010		2009		2010		2009
Charges incurred with Chase Oil and affiliates(a)	$	422	$	6,541	$	15,507	$	13,269
Working interests owned by employees:(b)
Revenues distributed to employees	$	93	$	32	$	171	$	62
Joint interest payments received from employees	$	345	$	245	$	575	$	884
Overriding royalty interests paid to Chase Oil affiliates(c)	$	517	$	258	$	1,046	$	499
Royalty interests paid to a director of the Company(d)	$	38	$	30	$	79	$	56
Amounts paid under consulting agreement with Steven L. Beal(e)	$	67	$	—	$	130	$	—

30

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

	June 30,		December 31,
(in thousands)	2010		2009
Amounts included in accounts receivable — related parties:
Chase Oil and affiliates(a)	$	197	$	87
Working interests owned by employees(b)	$	198	$	129
Amounts included in accounts payable — related parties:
Chase Oil and affiliates(a)	$	512	$	9
Working interests owned by employees(b)	$	9	$	15
Overriding royalty interests of Chase Oil affiliates(c)	$	319	$	255
Royalty interests of a director of the Company(d)	$	12	$	12

(a)	The Company incurred charges for services rendered in the ordinary course of business from Chase Oil Corporation (“Chase Oil”), a stockholder of the Company, and its affiliates including a drilling contractor, 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 tables above summarize the charges incurred as well as outstanding payables and receivables.
(b)	The Company purchased oil and natural gas properties from third parties in which employees of the Company owned a working interest. The tables above summarize the Company’s activities with these employees.
(c)	Certain persons affiliated with Chase Oil own overriding royalty interests in certain of the Company’s properties. The tables above summarize the amounts paid attributable to such interests and amounts due at period end.
(d)	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 owns a 3.5 percent partnership interest. The tables above summarize the amounts paid attributable to such interest and amounts due at period end.
(e)	On June 30, 2009, Steven L. Beal, the Company’s then President and Chief Operating Officer, retired from such positions. On June 9, 2009, the Company entered into a consulting agreement (the “Consulting Agreement”) with Mr. Beal, under which Mr. Beal began serving as a consultant to the Company on July 1, 2009. Either the Company or Mr. Beal may terminate the consulting relationship at any time by giving ninety days written notice to the other party; however, the Company may terminate the relationship immediately for cause. During the term of the consulting relationship, Mr. Beal will receive a consulting fee of $20,000 per month and a monthly reimbursement for his medical and dental coverage costs. If Mr. Beal dies during the term of the Consulting Agreement, his estate will receive a $60,000 lump sum payment. As part of the consulting agreement, certain of Mr. Beal’s stock-based awards were modified to permit vesting and exercise under the original terms of the stock-based awards as if Mr. Beal were still an employee of the Company while he is performing consulting services for the Company. The tables above summarize the Company’s activities pursuant to the consulting agreement with this director.

     Saltwater disposal services agreement.Among the assets the Company acquired from Chase Oil is an undivided interest in a saltwater gathering and disposal system, which is owned and maintained under a written agreement among the Company and Chase Oil and certain of its affiliates, and under which the Company as operator gathers and disposes of produced water. The system is owned jointly by the Company and Chase Oil and its affiliates in undivided ownership percentages, which are annually redetermined as of January 1 on the basis of each party’s percentage contribution of the total volume of produced water disposed of through the system during the prior calendar year. As of January 1, 2010, the Company owned 97.5 percent of the system and Chase Oil and its affiliates owned 2.5 percent.

     Purchase of residence.During the second quarter of 2010, the Company purchased the Houston, Texas residence of Darin G. Holderness, the Company’s Vice President, Chief Financial Officer and Treasurer. To effectuate the purchase, the Company

31

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

engaged a third-party relocation company, who executed the purchase for $920,000 and will subsequently sell Mr. Holderness’ residence. The third-party relocation company appraised the fair value of Mr. Holderness’ residence at $920,000.

Note N.Net income (loss) per share

     Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares treated as outstanding for the period.

     The computation of diluted income (loss) per share reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive to income (loss) 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 capital options, stock options and restricted stock (as issued under the Plan and described in Note G). 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, 2010 and 2009:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2010		2009		2010		2009
Weighted average common shares outstanding:
Basic		91,044		84,799		89,944		84,665
Dilutive capital options		437		—		498		—
Dilutive common stock options		432		—		418		—
Dilutive restricted stock		384		—		360		—
Diluted		92,297		84,799		91,220		84,665

     Because the Company reported a net loss for the three and six months ended June 30, 2009, a total of 2,403,336 stock options and 492,810 restricted shares, outstanding at June 30, 2009, were not included in the diluted loss per share computations. The inclusion of these equity instruments would have been anti-dilutive, therefore, the weighted average common shares reported for basic and diluted net loss per share were the same.

32

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

Note O.Other current liabilities

     The following table provides the components of the Company’s other current liabilities at June 30, 2010 and December 31, 2009:

	June 30,		December 31,
(in thousands)	2010		2009
Other current liabilities:
Accrued production costs	$	30,164	$	24,128
Payroll related matters		14,370		14,490
Accrued interest		8,215		10,055
Asset retirement obligations		2,429		3,262
Other		5,130		8,160
Other current liabilities	$	60,308	$	60,095

Note P.Subsidiary guarantors

     All of the Company’s wholly-owned subsidiaries have fully and unconditionally guaranteed the Senior Notes of the Company (see Note J). In accordance with practices accepted by the SEC, the Company has prepared Condensed Consolidating Financial Statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following Condensed Consolidating Balance Sheets at June 30, 2010 and December 31, 2009, and Condensed Consolidating Statements of Operations for the three and six months ended June 30, 2010 and 2009 and Condensed Consolidating Statements of Cash Flows for the six months ended June 30, 2010 and 2009, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc. as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors are not restricted from making distributions to the Company.

33

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

Condensed Consolidating Balance Sheet
June 30, 2010

	Parent		Subsidiary		Consolidating
(in thousands)	Issuer		Guarantors		Entries			Total
ASSETS
Accounts receivable — related parties	$	3,872,138	$	776,975	$	(4,648,718	)	$	395
Other current assets		37,121		183,136		—			220,257
Total oil and natural gas properties, net		—		3,067,398		—			3,067,398
Total property and equipment, net		—		16,304		—			16,304
Investment in subsidiaries		1,079,751		—		(1,079,751	)		—
Total other long-term assets		82,935		56,964		—			139,899
Total assets	$	5,071,945	$	4,100,777	$	(5,728,469	)	$	3,444,253
LIABILITIES AND EQUITY
Accounts payable — related parties	$	1,968,956	$	2,680,614	$	(4,648,718	)	$	852
Other current liabilities		27,943		318,853		—			346,796
Other long-term liabilities		668,676		21,559		—			690,235
Long-term debt		644,023		—		—			644,023
Equity		1,762,347		1,079,751		(1,079,751	)		1,762,347
Total liabilities and equity	$	5,071,945	$	4,100,777	$	(5,728,469	)	$	3,444,253

Condensed Consolidating Balance Sheet
December 31, 2009

	Parent		Subsidiary		Consolidating
(in thousands)	Issuer		Guarantors		Entries			Total
ASSETS
Accounts receivable — related parties	$	2,715,307	$	1,738,382	$	(4,453,473	)	$	216
Other current assets		33,561		183,481		—			217,042
Total oil and natural gas properties, net		—		2,840,583		—			2,840,583
Total property and equipment, net		—		15,706		—			15,706
Investment in subsidiaries		876,154		—		(876,154	)		—
Total other long-term assets		44,291		53,247		—			97,538
Total assets	$	3,669,313	$	4,831,399	$	(5,329,627	)	$	3,171,085
LIABILITIES AND EQUITY
Accounts payable — related parties	$	790,251	$	3,663,513	$	(4,453,473	)	$	291
Other current liabilities		68,706		268,017		—			336,723
Other long-term liabilities		629,092		23,715		—			652,807
Long-term debt		845,836		—		—			845,836
Equity		1,335,428		876,154		(876,154	)		1,335,428
Total liabilities and equity	$	3,669,313	$	4,831,399	$	(5,329,627	)	$	3,171,085

34

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

Condensed Consolidating Statement of Operations
Three Months Ended June 30, 2010

	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries			Total
Total operating revenues	$	—		$	215,710		$	—		$	215,710
Total operating costs and expenses		109,112			(114,411	)		—			(5,299	)
Income from operations		109,112			101,299			—			210,411
Interest expense		(11,192	)		—			—			(11,192	)
Other, net		100,995			(304	)		(100,995	)		(304	)
Income before income taxes		198,915			100,995			(100,995	)		198,915
Income tax expense		(74,744	)		—			—			(74,744	)
Net income	$	124,171		$	100,995		$	(100,995	)	$	124,171

Condensed Consolidating Statement of Operations
Three Months Ended June 30, 2009

	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries			Total
Total operating revenues	$	—		$	127,332		$	—		$	127,332
Total operating costs and expenses		(81,629	)		(98,592	)		—			(180,221	)
Income (loss) from operations		(81,629	)		28,740			—			(52,889	)
Interest expense		(6,200	)		—			—			(6,200	)
Other, net		28,920			180			(28,920	)		180
Income (loss) before income taxes		(58,909	)		28,920			(28,920	)		(58,909	)
Income tax benefit		25,691			—			—			25,691
Net income (loss)	$	(33,218	)	$	28,920		$	(28,920	)	$	(33,218	)

35

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

Condensed Consolidating Statement of Operations
Six Months Ended June 30, 2010

	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries			Total
Total operating revenues	$	—		$	427,710		$	—		$	427,710
Total operating costs and expenses		125,055			(223,736	)		—			(98,681	)
Income from operations		125,055			203,974			—			329,029
Interest expense		(22,257	)		—			—			(22,257	)
Other, net		203,597			(377	)		(203,597	)		(377	)
Income before income taxes		306,395			203,597			(203,597	)		306,395
Income tax expense		(114,684	)		—			—			(114,684	)
Net income	$	191,711		$	203,597		$	(203,597	)	$	191,711

Condensed Consolidating Statement of Operations
Six Months Ended June 30, 2009

	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries			Total
Total operating revenues	$	—		$	213,334		$	—		$	213,334
Total operating costs and expenses		(86,846	)		(196,010	)		—			(282,856	)
Income (loss) from operations		(86,846	)		17,324			—			(69,522	)
Interest expense		(10,570	)		—			—			(10,570	)
Other, net		17,176			(148	)		(17,176	)		(148	)
Income (loss) before income taxes		(80,240	)		17,176			(17,176	)		(80,240	)
Income tax benefit		33,797			—			—			33,797
Net income (loss)	$	(46,443	)	$	17,176		$	(17,176	)	$	(46,443	)

36

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2010

	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries		Total
Net cash flows (used in) provided by operating activities	$	(17,206	)	$	256,736		$	—	$	239,530
Net cash flows used in investing activities		(8,024	)		(294,141	)		—		(302,165	)
Net cash flows provided by financing activities		25,207			34,577			—		59,784
Net decrease in cash and cash equivalents		(23	)		(2,828	)		—		(2,851	)
Cash and cash equivalents at beginning of period		48			3,186			—		3,234
Cash and cash equivalents at end of period	$	25		$	358		$	—	$	383

Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2009

	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries		Total
Net cash flows provided by (used in) operating activities	$	(98,145	)	$	216,377		$	—	$	118,232
Net cash flows provided by (used in) investing activities		61,465			(224,293	)		—		(162,828	)
Net cash flows provided by (used in) financing activities		36,731			(6,806	)		—		29,925
Net increase (decrease) in cash and cash equivalents		51			(14,722	)		—		(14,671	)
Cash and cash equivalents at beginning of period		—			17,752			—		17,752
Cash and cash equivalents at end of period	$	51		$	3,030		$	—	$	3,081

37

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

Note Q.Subsequent events

     Marbob Acquisition. On July 19, 2010, the Company entered into an asset purchase agreement to acquire substantially all of the oil and natural gas leases, interests, properties and related assets owned by Marbob Energy Corporation and certain affiliated entities (collectively, “Marbob”) for aggregate consideration of approximately $1.65 billion, subject to purchase price adjustments, which include downward purchase price adjustments based on the exercise of third parties of contractual preferential rights to purchase certain interests in properties to be acquired from Marbob (the “Marbob Acquisition”). Upon closing, the consideration is expected to consist of (i) cash consideration in the aggregate amount of $1.45 billion, (ii) the issuance by the Company to Marbob of an 8 percent unsecured promissory note due 2018 in the aggregate principal amount of $150 million and (iii) the issuance to Marbob of approximately 1.1 million shares of the Company’s common stock (representing a negotiated value of $50 million). The Marbob Acquisition is expected to close on or before November 30, 2010.

     The Company intends to finance the $1.45 billion cash portion of the Marbob Acquisition with a combination of equity and debt. On July 19, 2010, the Company entered into a common stock purchase agreement with third-party investors to sell approximately 6.6 million shares of the Company’s common stock in a private placement for aggregate cash consideration of approximately $300 million. The Company anticipates that this private placement will close simultaneously with the Marbob Acquisition. In addition, the Company has received an $800 million underwritten commitment from two of its lenders under its Credit Facility to expand the size of its existing Credit Facility from $1.2 billion to $2.0 billion as part of the financing for the Marbob Acquisition, which the Company expects will provide the credit capacity to fund the remaining cash portion of the purchase price. The expanded credit facility is expected to close simultaneously with the Marbob Acquisition.

     Marbob preferential rights. Certain of the Marbob interests in properties contain contractual preferential rights to purchase by third parties if Marbob were to sell them. Marbob has informed the Company of the receipt by Marbob of a notice from BP America Production Company (“BP”) electing to exercise its contractual preferential purchase right under certain operating agreements to purchase interests in certain of Marbob’s properties as a result of the Marbob Acquisition. The approximate value of the interests in properties associated with this election is $400 million, which, if closed between Marbob and BP, would reduce the purchase price of the Marbob Acquisition.

     In addition, Marbob has contractual preferential rights under certain operating agreements to purchase certain interests in properties if third parties were to sell those interests in properties. On July 20, 2010, BP announced it was selling all its assets in the Permian Basin to a subsidiary of Apache Corporation (“Apache”). Marbob and BP own common interests in certain common properties subject to a contractual preferential right to purchase. BP and Apache have contested Marbob’s ability to exercise its contractual preferential rights in this situation. As a result, Marbob and the Company have filed suit against BP and Apache seeking declaratory judgment and injunctive relief to protect Marbob’s contractual right to have the option to purchase these interests in properties. The Company is unable to predict at this time if the court will grant Marbob and the Company the relief sought in connection with the suit.

38

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

     New commodity derivative contracts.In July 2010, the Company entered into the following oil price swaps to protect the Company’s cash flows in anticipation of the Marbob Acquisition:

	Aggregate		Index		Contract
	Volume		Price(a)		Period
Oil (volumes in Bbls):
Price swap		1,578,000	$	80.80		1/1/11 - 12/31/11
Price swap		1,305,000	$	81.39		1/1/12 - 12/31/12
Price swap		261,000	$	82.50		7/1/12 - 12/31/12
Price swap		1,380,000	$	82.58		1/1/13 - 12/31/13
Price swap		1,248,000	$	83.94		1/1/14 - 12/31/14
Price swap		600,000	$	84.50		1/1/15 - 6/30/15

(a) The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly average futures price.

39

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited

Note R.Supplementary information

Capitalized costs

	June 30,			December 31,
(in thousands)	2010			2009
Oil and natural gas properties:
Proved	$	3,465,443		$	3,139,424
Unproved		232,210			218,580
Less: accumulated depletion		(630,255	)		(517,421	)
Net capitalized costs for oil and natural gas properties	$	3,067,398		$	2,840,583

Costs incurred for oil and natural gas producing activities^(a)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(in thousands)	2010		2009			2010		2009
Property acquisition costs:
Proved	$	3,897	$	(68	)	$	13,739	$	(1,008	)
Unproved		15,673		3,361			21,029		4,582
Exploration		36,434		61,131			61,933		84,940
Development		134,206		31,450			245,912		115,229
Total costs incurred for oil and natural gas properties	$	190,210	$	95,874		$	342,613	$	203,743

(a) The costs incurred for oil and natural gas producing activities includes the following amounts of asset retirement obligations:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(in thousands)	2010		2009			2010			2009
Proved property acquisition costs	$	—	$	—		$	—		$	—
Exploration costs		184		52			252			220
Development costs		776		(3,878	)		(1,424	)		(2,727	)
Total	$	960	$	(3,826	)	$	(1,172	)	$	(2,507	)

40

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     The following discussion is intended to assist in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated financial statements and notes, as well as the selected historical consolidated financial data and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2009.

     During the fourth quarter of 2009, we closed the Wolfberry Acquisitions as discussed below. As a result of the acquisitions, many comparisons between periods will be difficult or impossible.

     Certain statements in our discussion below are forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause actual results to differ materially from these implied or expressed by the forward-looking statements. Please see “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

     We are an independent oil and natural gas company engaged in the acquisition, development and exploration of producing oil and natural gas properties. Our core operations are primarily focused in the Permian Basin of Southeast New Mexico and West Texas. We have also acquired significant acreage positions in and are actively involved in drilling or participating in drilling of emerging plays located in the Permian Basin of Southeast New Mexico and the Williston Basin of North Dakota, where we are applying horizontal drilling, advanced fracture stimulation and enhanced recovery technologies. Crude oil comprised 67 percent of our 211.5 million barrels of oil equivalent (“MMBoe”) of estimated net proved reserves at December 31, 2009, and 68 percent of our 6.7 MMBoe of production for the six months ended June 30, 2010. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 95.3 percent of our proved developed producing PV-10 and 66.4 percent of our 3,960 gross wells at December 31, 2009. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and stimulation methods used.

Commodity Prices

     Our results of operations are heavily influenced by commodity prices. Factors that may impact future commodity prices, including the price of oil and natural gas, include:

• developments generally impacting the Middle East, including Iraq and Iran;

• the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas;

• the current drilling moratorium in the Gulf of Mexico;

• the overall global demand for oil; and

• overall North American natural gas supply and demand fundamentals, including:

§	the impact of any decline in the United States economy,
§	weather conditions, and
§	liquefied natural gas deliveries to the United States.

     Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commodity hedge positions at June 30, 2010.

41

     Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, oil prices were substantially higher during the comparable periods of 2010 measured against 2009, while natural gas prices were moderately higher. The following table sets forth the average NYMEX oil and natural gas prices for the three and six months ended June 30, 2010 and 2009, as well as the high and low NYMEX prices for the same periods:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Average NYMEX prices:
Oil (Bbl)	$	78.12	$	59.83	$	78.36	$	51.61
Natural gas (MMBtu)	$	4.35	$	3.80	$	4.69	$	4.15
High / Low NYMEX prices:
Oil (Bbl):
High	$	86.84	$	72.68	$	86.84	$	72.68
Low	$	68.01	$	45.88	$	68.01	$	33.98
Natural gas (MMBtu):
High	$	5.19	$	4.45	$	6.01	$	6.07
Low	$	3.91	$	3.25	$	3.84	$	3.25

     Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $82.55 and $71.98 per Bbl and $4.92 and $4.31 per MMBtu, respectively, during the period from July 1, 2010 to August 4, 2010. At August 4, 2010, the NYMEX oil price and NYMEX natural gas price were $82.47 per Bbl and $4.74 per MMBtu, respectively.

Recent Events

     Marbob Acquisition. On July 19, 2010, we entered into an asset purchase agreement to acquire substantially all of the oil and natural gas leases, interests, properties and related assets owned by Marbob Energy Corporation and certain affiliated entities (collectively, “Marbob”) for aggregate consideration of approximately $1.65 billion, subject to purchase price adjustments, which include downward purchase price adjustments based on the exercise of third parties of contractual preferential rights to purchase certain interests in properties to be acquired from Marbob (the “Marbob Acquisition”). Upon closing, the consideration is expected to consist of (i) cash consideration in the aggregate amount of $1.45 billion, (ii) the issuance by us to Marbob of an 8 percent unsecured promissory note due 2018 in the aggregate principal amount of $150 million and (iii) the issuance to Marbob of approximately 1.1 million shares of our common stock (representing a negotiated value of $50 million). The Marbob Acquisition is expected to close on or before November 30, 2010.

     We intend to finance the $1.45 billion cash portion of the Marbob Acquisition with a combination of equity and debt. On July 19, 2010, we entered into a common stock purchase agreement with third-party investors to sell approximately 6.6 million shares of our common stock in a private placement for aggregate cash consideration of approximately $300 million. We anticipate that this private placement will close simultaneously with the Marbob Acquisition. In addition, we have received an $800 million underwritten commitment from two of our lenders under our Credit Facility to expand the size of our existing credit facility from $1.2 billion to $2.0 billion as part of the financing for the Marbob Acquisition, which we expect will provide the credit capacity to fund the remaining cash portion of the purchase price. The expanded credit facility is expected to close simultaneously with the Marbob Acquisition.

     Marbob preferential rights. Certain of the Marbob interests in properties contain contractual preferential rights to purchase by third parties if Marbob were to sell them. Marbob has informed us of the receipt by Marbob of a notice from BP America Production Company (“BP”) electing to exercise its contractual preferential purchase right under certain operating agreements to purchase interests in certain of Marbob’s properties as a result of the Marbob Acquisition. The approximate value of the interests in properties associated with this election is $400 million, which, if closed between Marbob and BP, would reduce the purchase price of the Marbob Acquisition.

     In addition, Marbob has contractual preferential rights under certain operating agreements to purchase certain interests in properties if third parties were to attempt to sell those interests in properties. On July 20, 2010, BP announced it was selling all its assets in the Permian Basin to a subsidiary of Apache Corporation (“Apache”). Marbob and BP own common interests in certain common properties subject to a contractual preferential right to purchase. BP and Apache have contested Marbob’s ability to exercise its contractual preferential rights in this situation. As a result,

42

Marbob and we have filed suit against BP and Apache seeking declaratory judgment and injunctive relief to protect Marbob’s contractual right to have the option to purchase these interests in properties. We are unable to predict at this time if the court will grant Marbob and us the relief sought in connection with the suit.

     Credit facility.In April 2010, we increased our borrowing base under our credit facility to $1.2 billion, an increase of $244.1 million. We had $852.0 million of availability under our credit facility at June 30, 2010. As part of the Marbob Acquisition, we have received an $800 million underwritten commitment from two of our lenders in our credit facility to further expand the size of our existing credit facility from $1.2 billion to $2.0 billion as part of the financing for the acquisition. We believe that the increased size of the credit facility will provide us the credit capacity to fund the Marbob Acquisition and maintain an adequate level of liquidity.

     Equity issuance.On February 1, 2010, we issued approximately 5.3 million shares of our common stock at $42.75 per share in a public offering. After deducting underwriting discounts of approximately $9.1 million and transaction costs, we received net proceeds of approximately $219.3 million. The net proceeds from this offering were used to repay a portion of the borrowings under our credit facility.

     Wolfberry acquisitions.In December 2009, together with the acquisition of related additional interests that closed in 2010, we closed two acquisitions of interests in producing and non-producing assets in the Wolfberry play of the Permian Basin for approximately $270.7 million in cash (the “Wolfberry Acquisitions”). The Wolfberry Acquisitions were primarily funded with borrowings under our credit facility. As of December 31, 2009, these acquisitions included estimated total proved reserves of 19.9 MMBoe, of which 69 percent were oil and 25 percent were proved developed. Our 2009 results of operations do not include any production, revenues or costs from the Wolfberry Acquisitions.

     2010 capital budget. In December 2009, we announced our 2010 capital budget of approximately $625 million, which we expected could be funded substantially within our cash flow. In August 2010, we announced the increase of our 2010 capital budget to $700 million. Based on current commodity prices and our expectations, we believe our 2010 revised capital budget will exceed our 2010 cash flow, excluding the effects of the Marbob Acquisition. As our size and financial flexibility have grown, we have a longer-term view on spending substantially within our cash flow, and our spending during any specific period may exceed our cash flow for that period. However, our capital budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in our drilling and completion costs, we may reduce our capital spending program to be substantially within our cash flow.

     Our capital budget does not include acquisitions (other than the customary purchase of leasehold acreage). Our 2010 capital budget does not include capital we may spend on the Marbob assets once we close the acquisition. The following is a summary of our 2010 capital budget:

	Original		Revised
	2010		2010
(in millions)	Budget		Budget
Drilling and recompletion opportunities in our core operating area	$	502	$	538
Projects operated by third parties		8		10
Emerging plays, acquisition of leasehold acreage and other property interests, and geological and geophysical		82		117
Facilities capital in our core operating areas		33		35
Total 2010 capital budget	$	625	$	700

     During the six months ended June 30, 2010, our cost incurred was approximately $330.0 million (excluding non leasehold acquisitions of approximately $13.7 million and asset retirement obligations). Originally our capital budget was front end loaded, and we expected to outspend our cash flow in the first half of 2010. We outspent our cash flow during the six months ended June 30, 2010 by approximately $60 million, including acquisitions.

Derivative Financial Instruments

     Derivative financial instrument exposure.At June 30, 2010, the fair value of our financial derivatives was a net asset of $70.8 million. All of our counterparties to these financial derivatives are party to our credit facility and have their outstanding debt commitments and derivative exposures collateralized pursuant to our credit facility. Under the terms of our financial derivative instruments and their collateralization under our credit facility, we do not have exposure to potential “margin calls” on our financial derivative

43

instruments. We currently have no reason to believe that our counterparties to these commodity derivative contracts are not financially viable. Our credit facility does not allow us to offset amounts we may owe a lender against amounts we may be owed related to our financial instruments with such party.

     New commodity derivative contracts.During the six months ended June 30, 2010, we entered into additional commodity derivative contracts to hedge a portion of our estimated future production. The following table summarizes information about these additional commodity derivative contracts for the six months ended June 30, 2010. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Aggregate		Index			Contract
	Volume		Price			Period
Oil (volumes in Bbls):
Price swap		670,000	$	83.72	(a)		1/1/10 - 12/31/10
Price swap		195,000	$	76.85	(a)		3/1/10 - 12/31/10
Price swap		1,463,000	$	88.63	(a)		5/1/10 - 12/31/10
Price swap		2,136,000	$	88.36	(a)		1/1/11 - 12/31/11
Price swap		2,268,000	$	92.68	(a)		1/1/12 - 12/31/12
Natural gas (volumes in MMBtus):
Price swap		418,000	$	5.99	(b)		2/1/10 - 12/31/10
Price swap		1,250,000	$	5.55	(b)		3/1/10 - 12/31/10
Price swap		5,076,000	$	6.14	(b)		1/1/11 - 12/31/11
Price swap		300,000	$	6.54	(b)		1/1/12 - 12/31/12

(a)	The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly average futures price.
(b)	The index prices for the natural gas price swaps are based on the NYMEX-Henry Hub last trading day futures price.

     In July 2010, we entered into the following oil price swaps to protect our cash flows in anticipation of the Marbob Acquisition:

	Aggregate		Index		Contract
	Volume		Price(a)		Period
Oil (volumes in Bbls):
Price swap		1,578,000	$	80.80		1/1/11 - 12/31/11
Price swap		1,305,000	$	81.39		1/1/12 - 12/31/12
Price swap		261,000	$	82.50		7/1/12 - 12/31/12
Price swap		1,380,000	$	82.58		1/1/13 - 12/31/13
Price swap		1,248,000	$	83.94		1/1/14 - 12/31/14
Price swap		600,000	$	84.50		1/1/15 - 6/30/15

(a) The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly average futures price.

44

Results of Operations

     The following table sets forth summary information concerning our production results, average sales prices and operating costs and expenses for the three and six months ended June 30, 2010 and 2009. The actual historical data in this table excludes results from the Wolfberry Acquisitions for periods prior to January 1, 2010.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Production and operating data:
Net production volumes:
Oil (MBbl)		2,337		1,831		4,507		3,518
Natural gas (MMcf)		6,692		5,414		12,933		10,369
Total (MBoe)		3,452		2,733		6,663		5,246
Average daily production volumes:
Oil (Bbl)		25,681		20,121		24,901		19,436
Natural gas (Mcf)		73,538		59,495		71,453		57,287
Total (Boe)		37,938		30,037		36,809		28,984
Average prices:
Oil, without derivatives (Bbl)	$	74.64	$	55.44	$	74.81	$	47.32
Oil, with derivatives (Bbl)(a)	$	73.42	$	67.36	$	71.93	$	63.36
Natural gas, without derivatives (Mcf)	$	6.17	$	4.77	$	7.00	$	4.52
Natural gas, with derivatives (Mcf)(a)	$	7.01	$	5.38	$	7.48	$	5.08
Total, without derivatives (Boe)	$	62.49	$	46.59	$	64.19	$	40.67
Total, with derivatives (Boe)(a)	$	63.29	$	55.78	$	63.16	$	52.53
Operating costs and expenses per Boe:
Lease operating expenses and workover costs	$	6.71	$	5.75	$	6.29	$	6.24
Oil and natural gas taxes	$	5.01	$	3.69	$	5.29	$	3.40
Depreciation, depletion and amortization	$	15.67	$	19.17	$	16.20	$	19.66
General and administrative	$	5.08	$	5.19	$	4.67	$	4.94

(a) Includes the effect of the cash settlements received from (paid on) commodity derivatives not designated as hedges and reported in operating costs and expenses. The following table reflects the amounts of cash settlements received from (paid on) commodity derivatives not designated as hedges that were included in computing average prices with derivatives and reconciles to the amount in gain (loss) on derivatives not designated as hedges as reported in the consolidated statements of operations:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2010			2009			2010			2009
Gain (loss) on derivatives not designated as hedges:
Cash (payments on) receipts from oil derivatives	$	(2,852	)	$	21,828		$	(12,985	)	$	56,412
Cash receipts from natural gas derivatives		5,614			3,292			6,120			5,832
Cash payments on interest rate derivatives		(1,221	)		(779	)		(2,434	)		(779	)
Unrealized mark-to-market gain (loss) on commodity and interest rate derivatives		111,222			(105,947	)		137,635			(148,117	)
Gain (loss) on derivatives not designated as hedges	$	112,763		$	(81,606	)	$	128,336		$	(86,652	)

45

     The following table presents selected financial and operating information for the fields which represented greater than 15 percent of our total proved reserves at December 31, 2009 and 2008, respectively:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010				2009		2010				2009
	West		Grayburg		Grayburg		West		Grayburg		Grayburg
	Wolfberry		Jackson		Jackson		Wolfberry		Jackson		Jackson
Production and operating data:
Net production volumes:
Oil (MBbl)		357		388		324		687		797		648
Natural gas (MMcf)		993		1,135		962		1,978		2,282		1,904
Total (MBoe)		523		577		484		1,017		1,177		965
Average prices:
Oil, without derivatives (Bbl)	$	77.09	$	74.38	$	56.56	$	76.93	$	74.89	$	46.71
Natural gas, without derivatives (Mcf)	$	6.41	$	6.67	$	4.74	$	7.39	$	7.39	$	4.65
Total, without derivatives (Boe)	$	64.86	$	63.12	$	47.24	$	66.36	$	65.02	$	40.52
Production costs per Boe:
Lease operating expenses including workovers	$	4.16	$	6.75	$	6.40	$	4.41	$	6.19	$	6.38
Oil and natural gas taxes	$	4.29	$	5.47	$	4.02	$	4.41	$	5.61	$	3.49

46

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

     Oil and natural gas revenues.Revenue from oil and natural gas operations was $215.7 million for the three months ended June 30, 2010, an increase of $88.4 million (69 percent) from $127.3 million for the three months ended June 30, 2009. This increase was primarily due to substantial increases in realized oil and natural gas prices and increased production (i) as a result of the Wolfberry Acquisitions and (ii) due to successful drilling efforts during 2009 and 2010. Specifically the:

• average realized oil price (excluding the effects of derivative activities) was $74.64 per Bbl during the three months ended June 30, 2010, an increase of 35 percent from $55.44 per Bbl during the three months ended June 30, 2009;

• total oil production was 2,337 MBbl for the three months ended June 30, 2010, an increase of 506 MBbl (28 percent) from 1,831 MBbl for the three months ended June 30, 2009;

• average realized natural gas price (excluding the effects of derivative activities) was $6.17 per Mcf during the three months ended June 30, 2010, an increase of 29 percent from $4.77 per Mcf during the three months ended June 30, 2009; and

• total natural gas production was 6,692 MMcf for the three months ended June 30, 2010, an increase of 1,278 MMcf (24 percent) from 5,414 MMcf for the three months ended June 30, 2009.

     Production expenses.The following table provides the components of our total oil and natural gas production costs for the three months ended June 30, 2010 and 2009:

	Three Months Ended
	June 30,
	2010				2009
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Lease operating expenses	$	20,339	$	5.89	$	15,726	$	5.75
Taxes:
Ad valorem		2,237		0.65		989		0.36
Production		15,055		4.36		9,090		3.33
Workover costs		2,817		0.82		12		—
Total oil and natural gas production expenses	$	40,448	$	11.72	$	25,817	$	9.44

     Among the cost components of production expenses, in general, we have some control over lease operating expenses and workover costs on properties we operate, but production and ad valorem taxes are directly related to commodity price changes.

     Lease operating expenses were $20.3 million ($5.89 per Boe) for the three months ended June 30, 2010, an increase of $4.6 million (29 percent) from $15.7 million ($5.75 per Boe) for the three months ended June 30, 2009. The increase in lease operating expenses was primarily due to (i) our wells successfully drilled and completed in 2009 and 2010 and (ii) additional interests acquired in the Wolfberry Acquisitions in December 2009. The increase in lease operating expenses per Boe was in part due to incurrence of some non-routine costs during the three months ended June 30, 2010, offset in part by additional production from our wells successfully drilled and completed in 2009 and 2010 where we are receiving benefits from economies of scale.

     Ad valorem taxes have increased primarily as a result of increased valuations of our Texas properties, and the increase in our number of wells primarily associated with the Wolfberry Acquisitions and 2009 and 2010 drilling activity.

     Production taxes per unit of production were $4.36 per Boe during the three months ended June 30, 2010, an increase of 31 percent from $3.33 per Boe during the three months ended June 30, 2009. The increase was directly related to the increase in commodity prices and our increase in oil and natural gas revenues related to increased volumes. Over the same period, our per Boe prices (excluding the effects of derivatives) increased 34 percent.

47

     Workover expenses were approximately $2.8 million for the three months ended June 30, 2010, which were primarily related to increased workovers in the New Mexico Permian area due to work performed to restore production.

     Exploration and abandonments expense.The following table provides a breakdown of our exploration and abandonments expense for the three months ended June 30, 2010 and 2009:

	Three Months Ended
	June 30,
(in thousands)	2010		2009
Geological and geophysical	$	560	$	448
Exploratory dry holes		—		445
Leasehold abandonments and other		318		531
Total exploration and abandonments	$	878	$	1,424

     Our geological and geophysical expense, which primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, was $0.6 million and $0.4 million for the three months ended June 30, 2010 and 2009, respectively.

     During the three months ended June 30, 2009, we wrote-off two unsuccessful exploratory wells in our Texas Permian area.

     For the three months ended June 30, 2010, we recorded $0.3 million of leasehold abandonments, which were primarily related to non-core prospects in our Texas Permian area. For the three months ended June 30, 2009, we recorded approximately $0.5 million of leasehold abandonments, which related primarily to the write-off of a non-core prospect in our New Mexico Permian area.

     Depreciation, depletion and amortization expense.The following table provides components of our depreciation, depletion and amortization expense for the three months ended June 30, 2010 and 2009:

	Three Months Ended
	June 30,
	2010				2009
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties	$	53,001	$	15.35	$	51,218	$	18.74
Depreciation of other property and equipment		713		0.21		796		0.29
Amortization of intangible asset — operating rights		387		0.11		388		0.14
Total depletion, depreciation and amortization	$	54,101	$	15.67	$	52,402	$	19.17
Oil price used to estimate proved oil reserves at period end	$	72.23			$	66.25
Natural gas price used to estimate proved natural gas reserves at period end	$	4.10			$	3.72

     Depletion of proved oil and natural gas properties was $53.0 million ($15.35 per Boe) for the three months ended June 30, 2010, an increase of $1.8 million from $51.2 million ($18.74 per Boe) for the three months ended June 30, 2009. The increase in depletion expense was primarily due to capitalized costs associated with new wells that were successfully drilled and completed in 2009 and 2010 and the Wolfberry Acquisitions, and was offset in part by the increase in the oil and natural gas prices between the periods utilized to determine proved reserves. The decrease in depletion expense per Boe was primarily due to (i) the increase in the oil and natural gas prices between the periods utilized to determine proved reserves, (ii) the increase in proved reserves from the successful 2009 and 2010 drilling of unproved properties and (iii) the increase in total proved reserves due to the new SEC rules related to disclosures of oil and natural gas reserves.

     On December 31, 2009, we adopted the new SEC rules related to disclosures of oil and natural gas reserves. As a result of these new SEC rules, we recorded an additional 13.6 MMBoe of proved reserves in 2009. We included the additional proved reserves in our depletion computation in the fourth quarter of 2009 and first two quarters of 2010. Our second quarter of 2010 depletion expense rate

48

was $15.35 per Boe, which is lower than past quarters in part due to these additional proved reserves. In the future, making comparisons to prior periods as it relates to our depletion rate may be difficult as a result of these new SEC rules.

     The amortization of the intangible asset is a result of the value assigned to the operating rights that we acquired in the July 2008 acquisition of Henry Petroleum LP and certain entities and individuals affiliated with Henry Petroleum LP (collectively the “Henry Entities”). The intangible asset is currently being amortized over an estimated life of approximately 25 years.

     Impairment of long-lived assets.We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Due primarily to downward adjustments to the economically recoverable proved reserves associated with declines in well performance, we recognized a non-cash charge against earnings of $4.7 million during the three months ended June 30, 2010, which was primarily attributable to natural gas related properties in our New Mexico Permian area. For the three months ended June 30, 2009, we recognized a non-cash charge against earnings of $4.5 million, which was primarily attributable to natural gas related, non-core properties, in our New Mexico Permian area.

     General and administrative expenses.The following table provides components of our general and administrative expenses for the three months ended June 30, 2010 and 2009:

	Three Months Ended
	June 30,
	2010						2009
				Per						Per
(in thousands, except per unit amounts)	Amount			Boe			Amount			Boe
General and administrative expenses — recurring	$	15,875		$	4.60		$	12,025		$	4.40
Non-recurring bonus paid to Henry Entities’ employees, see Note K		2,470			0.72			2,750			1.01
Non-cash stock-based compensation — stock options		579			0.17			885			0.32
Non-cash stock-based compensation — restricted stock		2,292			0.66			1,303			0.48
Less: Third-party operating fee reimbursements		(3,678	)		(1.07	)		(2,791	)		(1.02	)
Total general and administrative expenses	$	17,538		$	5.08		$	14,172		$	5.19

     General and administrative expenses were $17.5 million ($5.08 per Boe) for the three months ended June 30, 2010, an increase of $3.3 million (24 percent) from $14.2 million ($5.19 per Boe) for the three months ended June 30, 2009. The increase in general and administrative expenses was primarily due to (i) an increase in non-cash stock-based compensation for stock-based compensation awards and (ii) an increase in the number of employees and related personnel expenses to handle our increased activities, partially offset by an increase in third-party operating fee reimbursements. The decrease in total general and administrative expenses per Boe was primarily due to increased production associated with (i) additional production from our wells successfully drilled and completed in 2009 and 2010 and (ii) additional production from our Wolfberry Acquisitions for which we added no administrative personnel.

     In connection with the Henry Entities acquisition in July 2008, we agreed to pay certain of the Henry Entities’ former employees a predetermined bonus amount, in addition to the compensation we pay these employees, at each of the first and second anniversaries of the closing of the acquisition. Since these employees will earn this bonus over the two years following the acquisition and it is outside of our control, we are reflecting the cost in our general and administrative costs as non-recurring. See Note K of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information related to this bonus.

     We earn reimbursements as operator of certain oil and natural gas properties in which we own interests. As such, we earned reimbursements of $3.7 million and $2.8 million during the three months ended June 30, 2010 and 2009, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations.

49

     (Gain) loss on derivatives not designated as hedges.The following table sets forth the cash settlements and the non-cash mark-to-market adjustment for the derivative contracts not designated as hedges for the three months ended June 30, 2010 and 2009:

	Three Months Ended
	June 30,
(in thousands)	2010			2009
Cash payments (receipts):
Commodity derivatives — oil	$	2,852		$	(21,828	)
Commodity derivatives — natural gas		(5,614	)		(3,292	)
Financial derivatives — interest		1,221			779
Mark-to-market (gain) loss:
Commodity derivatives — oil		(119,303	)		105,062
Commodity derivatives — natural gas		6,509			4,312
Financial derivatives — interest		1,572			(3,427	)
(Gain) loss on derivatives not designated as hedges	$	(112,763	)	$	81,606

     Interest expense.The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the three months ended June 30, 2010 and 2009:

	Three Months Ended
	June 30,
	2010			2009
Interest expense (in thousands)	$	11,192		$	6,200
Weighted average interest rate		5.4	%		2.9	%
Weighted average debt balance (in millions)	$	663.4		$	680.0

     The increase in interest expense of approximately $5.0 million was due to interest costs on our 8.625 percent unsecured senior notes that were issued in September 2009. The decrease in the weighted average debt balance during the three months ended June 30, 2010 was due to partial repayment on our credit facility in February 2010 with the net proceeds of our equity offering. The increase in the weighted average interest rate was primarily due to the interest rate on our unsecured senior notes coupled with an increase in market interest rates, which increases the rate on borrowings under our credit facility.

     Income tax provisions.We recorded income tax expense of $74.7 million and an income tax benefit of $25.7 million for the three months ended June 30, 2010 and 2009, respectively. The effective income tax rate for the three months ended June 30, 2010 and 2009 was 37.6 percent and 43.6 percent, respectively.

50

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

     Oil and natural gas revenues.Revenue from oil and natural gas operations was $427.7 million for the six months ended June 30, 2010, an increase of $214.4 million (101 percent) from $213.3 million for the six months ended June 30, 2009. This increase was primarily due to substantial increases in realized oil and natural gas prices and increased production (i) as a result of the Wolfberry Acquisitions and (ii) due to successful drilling efforts during 2009 and 2010. Specifically the:

• average realized oil price (excluding the effects of derivative activities) was $74.81 per Bbl during the six months ended June 30, 2010, an increase of 58 percent from $47.32 per Bbl during the six months ended June 30, 2009;

• total oil production was 4,507 MBbl for the six months ended June 30, 2010, an increase of 989 MBbl (28 percent) from 3,518 MBbl for the six months ended June 30, 2009;

• average realized natural gas price (excluding the effects of derivative activities) was $7.00 per Mcf during the six months ended June 30, 2010, an increase of 55 percent from $4.52 per Mcf during the six months ended June 30, 2009; and

• total natural gas production was 12,933 MMcf for the six months ended June 30, 2010, an increase of 2,564 MMcf (25 percent) from 10,369 MMcf for the six months ended June 30, 2009.

     Production expenses.The following table provides the components of our total oil and natural gas production costs for the six months ended June 30, 2010 and 2009:

	Six Months Ended
	June 30,
	2010				2009
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Lease operating expenses	$	38,715	$	5.81	$	32,294	$	6.16
Taxes:
Ad valorem		5,192		0.78		2,491		0.47
Production		30,053		4.51		15,365		2.93
Workover costs		3,188		0.48		433		0.08
Total oil and natural gas production expenses	$	77,148	$	11.58	$	50,583	$	9.64

     Among the cost components of production expenses, in general, we have some control over lease operating expenses and workover costs on properties we operate, but production and ad valorem taxes are directly related to commodity price changes.

     Lease operating expenses were $38.7 million ($5.81 per Boe) for the six months ended June 30, 2010, an increase of $6.4 million (20 percent) from $32.3 million ($6.16 per Boe) for the six months ended June 30, 2009. The increase in lease operating expenses was primarily due to (i) our wells successfully drilled and completed in 2009 and 2010 and (ii) additional interests acquired in the Wolfberry Acquisitions in December 2009. The decrease in lease operating expenses per Boe was primarily due to additional production from our wells successfully drilled and completed in 2009 and 2010 where we are receiving benefits from economies of scale, offset in part by the incurrence of some non-routine costs during the six months ended June 30, 2010.

     Ad valorem taxes have increased primarily as a result of increased valuations of our Texas properties and the increase in our number of wells primarily associated with the Wolfberry Acquisitions and 2009 and 2010 drilling activity.

     Production taxes per unit of production were $4.51 per Boe during the six months ended June 30, 2010, an increase of 54 percent from $2.93 per Boe during the six months ended June 30, 2009. The increase was directly related to the increase in commodity prices and our increase in oil and natural gas revenues related to increased volumes. Over the same period, our per Boe prices (excluding the effects of derivatives) increased 58 percent.

51

     Workover expenses were approximately $3.2 million and $0.4 million for the six months ended June 30, 2010 and 2009, respectively. The 2010 amounts related primarily to increased workovers in our New Mexico Permian area due to work performed to restore production, whereas the 2009 amounts related primarily to workovers in our Texas Permian area.

     Exploration and abandonments expense.The following table provides a breakdown of our exploration and abandonments expense for the six months ended June 30, 2010 and 2009:

	Six Months Ended
	June 30,
(in thousands)	2010		2009
Geological and geophysical	$	1,228	$	1,125
Exploratory dry holes		218		1,866
Leasehold abandonments and other		727		4,428
Total exploration and abandonments	$	2,173	$	7,419

     Our geological and geophysical expense, which primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, was approximately $1.2 million and $1.1 million for the six months ended June 30, 2010 and 2009, respectively.

     During the six months ended June 30, 2009, we wrote-off an unsuccessful exploratory well in our Arkansas emerging play and two unsuccessful exploratory wells in our Texas Permian area.

     For the six months ended June 30, 2010, we recorded $0.7 million of leasehold abandonments, which were primarily related to non-core prospects in our Texas Permian area. For the six months ended June 30, 2009, we recorded approximately $4.4 million of leasehold abandonments, which related primarily to the write-off of four non-core prospects in our New Mexico Permian area and three non-core prospects in our Texas Permian area.

     Depreciation, depletion and amortization expense.The following table provides components of our depreciation, depletion and amortization expense for the six months ended June 30, 2010 and 2009:

	Six Months Ended
	June 30,
	2010				2009
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties	$	105,768	$	15.87	$	100,995	$	19.25
Depreciation of other property and equipment		1,402		0.21		1,374		0.26
Amortization of intangible asset — operating rights		774		0.12		781		0.15
Total depletion, depreciation and amortization	$	107,944	$	16.20	$	103,150	$	19.66
Oil price used to estimate proved oil reserves at period end	$	72.23			$	66.25
Natural gas price used to estimate proved natural gas reserves at period end	$	4.10			$	3.72

     Depletion of proved oil and natural gas properties was $105.8 million ($15.87 per Boe) for the six months ended June 30, 2010, an increase of $4.8 million from $101.0 million ($19.25 per Boe) for the six months ended June 30, 2009. The increase in depletion expense was primarily due to capitalized costs associated with new wells that were successfully drilled and completed in 2009 and 2010 and the Wolfberry Acquisitions, and was offset in part by the increase in the oil and natural gas prices between the periods utilized to determine proved reserves. The decrease in depletion expense per Boe was primarily due to (i) the increase in the oil and natural gas prices between the periods utilized to determine proved reserves, (ii) the increase in proved reserves from the successful 2009 and 2010 drilling of unproved properties and (iii) the increase in total proved reserves due to the new SEC rules related to disclosures of oil and natural gas reserves.

52

     On December 31, 2009, we adopted the new SEC rules related to disclosures of oil and natural gas reserves. As a result of these new SEC rules, we recorded an additional 13.6 MMBoe of proved reserves in 2009. We included the additional proved reserves in our depletion computation in the fourth quarter of 2009 and first two quarters of 2010. Our depletion expense rate for the six months ended June 30, 2010, was $15.87 per Boe, which is lower than the same period last year in part due to these additional proved reserves. In the future, making comparisons to prior periods as it relates to our depletion rate may be difficult as a result of these new SEC rules.

     The amortization of the intangible asset is a result of the value assigned to the operating rights that we acquired in the July 2008 acquisition of Henry Petroleum LP and certain entities and individuals affiliated with the Henry Entities. The intangible asset is currently being amortized over an estimated life of approximately 25 years.

     Impairment of long-lived assets.We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Due primarily to downward adjustments to the economically recoverable proved reserves associated with declines in well performance, we recognized a non-cash charge against earnings of $7.3 million during the six months ended June 30, 2010, which was primarily attributable to natural gas related properties in our New Mexico Permian area. For the six months ended June 30, 2009, we recognized a non-cash charge against earnings of $8.6 million, which was primarily attributable to non-core, natural gas related properties in our New Mexico Permian area.

     General and administrative expenses.The following table provides components of our general and administrative expenses for the six months ended June 30, 2010 and 2009:

	Six Months Ended
	June 30,
	2010						2009
				Per						Per
(in thousands, except per unit amounts)	Amount			Boe			Amount			Boe
General and administrative expenses — recurring	$	26,996		$	4.05		$	21,939		$	4.18
Non-recurring bonus paid to Henry Entities’ employees, see Note K		4,938			0.74			5,311			1.01
Non-cash stock-based compensation — stock options		1,588			0.24			1,913			0.37
Non-cash stock-based compensation — restricted stock		4,114			0.62			2,200			0.42
Less: Third-party operating fee reimbursements		(6,540	)		(0.98	)		(5,445	)		(1.04	)
Total general and administrative expenses	$	31,096		$	4.67		$	25,918		$	4.94

     General and administrative expenses were $31.1 million ($4.67 per Boe) for the six months ended June 30, 2010, an increase of $5.2 million (20 percent) from $25.9 million ($4.94 per Boe) for the six months ended June 30, 2009. The increase in general and administrative expenses was primarily due to (i) an increase in non-cash stock-based compensation for stock-based compensation awards and (ii) an increase in the number of employees and related personnel expenses to handle our increased activities, partially offset by an increase in third-party operating fee reimbursements. The decrease in total general and administrative expenses per Boe was primarily due to increased production associated with (i) additional production from our wells successfully drilled and completed in 2009 and 2010 and (ii) additional production from our Wolfberry Acquisitions for which we added no administrative personnel.

     In connection with the Henry Entities acquisition in July 2008, we agreed to pay certain of the Henry Entities’ former employees a predetermined bonus amount, in addition to the compensation we pay these employees, at each of the first and second anniversaries of the closing of the acquisition. Since these employees will earn this bonus over the two years following the acquisition and it is outside of our control, we are reflecting the cost in our general and administrative costs as non-recurring. See Note K of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information related to this bonus.

     We earn reimbursements as operator of certain oil and natural gas properties in which we own interests. As such, we earned reimbursements of $6.5 million and $5.4 million during the six months ended June 30, 2010 and 2009, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations.

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     (Gain) loss on derivatives not designated as hedges.The following table sets forth the cash settlements and the non-cash mark-to-market adjustment for the derivative contracts not designated as hedges for the six months ended June 30, 2010 and 2009:

	Six Months Ended
	June 30,
(in thousands)	2010			2009
Cash payments (receipts):
Commodity derivatives — oil	$	12,985		$	(56,412	)
Commodity derivatives — natural gas		(6,120	)		(5,832	)
Financial derivatives — interest		2,434			779
Mark-to-market (gain) loss:
Commodity derivatives — oil		(120,741	)		144,099
Commodity derivatives — natural gas		(20,678	)		5,018
Financial derivatives — interest		3,784			(1,000	)
(Gain) loss on derivatives not designated as hedges	$	(128,336	)	$	86,652

     Interest expense.The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the six months ended June 30, 2010 and 2009:

	Six Months Ended
	June 30,
	2010			2009
Interest expense (in thousands)	$	22,257		$	10,570
Weighted average interest rate		5.3	%		2.5	%
Weighted average debt balance (in millions)	$	687.1		$	668.0

     The increase in interest expense of approximately $11.7 million is due to interest costs on our 8.625 percent unsecured senior notes that were issued in September 2009. The increase in the weighted average debt balance during the six months ended June 30, 2010 is due to our borrowings under our credit facility to finance the Wolfberry Acquisitions, offset by a partial repayment on our credit facility in February 2010 with the net proceeds of our equity offering. The increase in the weighted average interest rate is primarily due to the interest rate on our unsecured senior notes coupled with an increase in market interest rates, which increases the rate on borrowings under our credit facility.

     Income tax provisions.We recorded income tax expense of $114.7 million and an income tax benefit of $33.8 million for the six months ended June 30, 2010 and 2009, respectively. The effective income tax rate for the six months ended June 30, 2010 and 2009 was 37.4 percent and 42.1 percent, respectively.

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Capital Commitments, Capital Resources and Liquidity

     Capital commitments.Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, financing under our credit facility, proceeds from the disposition of assets or alternative financing sources, as discussed in “Capital resources” below.

     Oil and natural gas properties.Our costs incurred on oil and natural gas properties, excluding acquisitions and asset retirement obligations, during the six months ended June 30, 2010 and 2009 totaled $309.0 million and $202.7 million, respectively, as compared to the comparable amount in cash flows used by investing activities of $278.0 million and $223.3 million for the respective periods. The primary reason for the differences in the costs incurred and cash flow expenditures is the timing of payments. These expenditures in 2010 were primarily funded by cash flow from operations (including effects of cash settlements received from (paid on) derivatives not designated as hedges).

     In December 2009, we announced our 2010 capital budget of approximately $625 million, which we expected could be funded substantially within our cash flow. In August 2010, we announced the increase of our 2010 capital budget to $700 million. Based on current commodity prices and our expectations, we believe our 2010 revised capital budget will exceed our 2010 cash flow, excluding the effects of the Marbob Acquisition.Originally our capital budget was front end loaded, and we expected to outspend our cash flow in the first half of 2010. We outspent our cash flow during the six months ended June 30, 2010 by approximately $60 million, including acquisitions. As our size and financial flexibility has grown, we have a longer-term view on spending substantially within our cash flow, and our spending during any specific period may exceed our cash flow for that period. However, our capital budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in our drilling and completion costs, we may reduce our capital spending program to be substantially within our cash flow. Our capital budget does not include acquisitions (other than the customary purchase of leasehold acreage). Our 2010 capital budget does not include capital we may spend on the Marbob assets once we close the acquisition.

     On July 19, 2010, we entered into an asset purchase agreement to acquire substantially all of the oil and natural gas leases, interests, properties and related assets owned by Marbob for aggregate consideration of approximately $1.65 billion, subject to purchase price adjustments, which include downward purchase price adjustments based on the exercise of third parties of contractual preferential rights to purchase certain interests in properties to be acquired from Marbob. Upon closing, the consideration consists of (i) cash consideration in the aggregate amount of $1.45 billion, (ii) the issuance by us to Marbob of an 8 percent unsecured promissory note due 2018 in the aggregate principal amount of $150 million and (iii) the issuance to Marbob of approximately 1.1 million shares of our common stock. As previously discussed, Marbob has informed us of the receipt by Marbob of a notice from BP electing to exercise its contractual preferential right under certain operating agreements to purchase certain Marbob interests in properties as a result of the announcement of the Marbob Acquisition which have an approximate allocated value of $400 million. The result of this would reduce the purchase price associated with the Marbob Acquisition. The Marbob Acquisition is expected to close on or before November 30, 2010. Though no assurances can be given, we are targeting an anticipated closing date of October 1, 2010. Assuming the acquisition closes on October 1, 2010 and no contractual preferential rights to purchase interests in properties have been exercised, we estimate we would spend approximately $70 million on drilling and related expenditures during the fourth quarter of 2010 that is not currently reflected in our revised 2010 capital budget.

     Other than the purchase of leasehold acreage, our revised 2010 capital budget is exclusive of acquisitions (including the Marbob Acquisition). We do not have a specific acquisition budget, since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek to acquire oil and natural gas properties that provide opportunities for the addition of reserves and production through a combination of development, high-potential exploration and control of operations that will allow us to apply our operating expertise.

     Although we cannot provide any assurance, we generally attempt to fund our non-acquisition expenditures with our available cash and cash flow, as adjusted from time to time; however, we may also use our credit facility, or other alternative financing sources, to fund such expenditures. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the availability of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions. In addition, under certain circumstances we would consider increasing or reallocating our revised 2010 capital budget.

     Acquisitions.Our expenditures for acquisitions of proved and unproved properties (which include leasehold acquisitions) during the three months ended June 30, 2010 and 2009 totaled approximately $19.6 million and $3.3 million, respectively, and approximately $34.8 million and $3.6 million during the six months ended June 30, 2010 and 2009, respectively. The proved acquisitions during the six months ended June 30, 2010, primarily relate to additional interests that we closed in 2010 on the Wolfberry Acquisitions and the acquisition of other Wolfberry assets.

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     Contractual obligations.Our contractual obligations include long-term debt, cash interest expense on debt, operating lease obligations, drilling commitments, employment agreements with executive officers, contractual bonus payments, derivative liabilities and other obligations. Since December 31, 2009, the material changes in our contractual obligations included a $202 million decrease in outstanding long-term borrowings, a $38.8 million decrease in cash interest expense on debt and our net commodity derivative is now in an asset position. See Note J of Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our long-term debt and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for information regarding the interest on our long-term debt and information on changes in the fair value of our open derivative obligations during the six months ended June 30, 2010.

     Off-balance sheet arrangements.Currently, we do not have any material off-balance sheet arrangements.

     Capital resources.Our primary sources of liquidity have been cash flows generated from operating activities (including the cash settlements received from (paid on) derivatives not designated as hedges presented in our investing activities) and financing provided by our credit facility. We believe that funds from our cash flows may not be adequate to meet both our short-term working capital requirements and our revised 2010 capital expenditure plans (excluding the effects from the Marbob Acquisition). We believe we have adequate availability under our credit facility to fund cash flow deficits, though we may reduce our capital spending program to remain substantially within our cash flow.

     Cash flow from operating activities.Our net cash provided by operating activities was $239.5 million and $118.2 million for the six months ended June 30, 2010 and 2009, respectively. The increase in operating cash flows during the six months ended June 30, 2010 over the same period in 2009 was principally due to increases in average realized oil and natural gas prices coupled with increased production.

     Cash flow used in investing activities.During the six months ended June 30, 2010 and 2009, we invested $291.4 million and $223.3 million, respectively, for additions to, and acquisitions of, oil and natural gas properties, inclusive of dry hole costs. Cash flows used in investing activities were higher during the six months ended June 30, 2010 over 2009, due to the Wolfberry Acquisitions and an increase in our capital expenditures on oil and natural gas properties, offset by settlements paid on derivatives not designated as hedges during the six months ended June 30, 2010 as compared to receipts on derivatives not designated as hedges in the comparable period in 2009.

     Cash flow from financing activities.Net cash provided by financing activities was $59.8 million and $29.9 million for the six months ended June 30, 2010 and 2009, respectively. During the six months ended June 30, 2010, we reduced our outstanding balance on our credit facility by $202 million primarily using proceeds from the issuance of common stock. During the six months ended June 30, 2009, we had net borrowings of $30.0 million under our credit facility.

     Our credit facility, as amended, has a maturity date of July 31, 2013. At June 30, 2010, we had letters of credit outstanding under the credit facility of approximately $25,000, and our availability to borrow additional funds was approximately $852.0 million based on the borrowing base of $1.2 billion. The next scheduled borrowing base redetermination is in October 2010. Between scheduled borrowing base redeterminations, we and, if requested by 66 2/3 percent of the lenders, the lenders, may each request one special redetermination.

     We have received an $800 million underwritten commitment from two of our lenders under our credit facility to expand the size of our existing credit facility from $1.2 billion to $2.0 billion as part of the financing for the Marbob Acquisition, which we expect will provide the credit capacity to fund the remaining cash portion of the purchase price. The expanded credit facility is expected to close simultaneously with the Marbob Acquisition.

     Advances on the credit facility bear interest, at our option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) (3.25 percent at June 30, 2010) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). At June 30, 2010, the interest rates of Eurodollar rate advances and JPM Prime Rate advances vary, with interest margins ranging from 200 to 300 basis points and 112.5 to 212.5 basis points, respectively, per annum depending on the debt balance outstanding. At June 30, 2010, we paid commitment fees on the unused portion of the available borrowing base of 50 basis points per annum.

     In conducting our business, we may utilize various financing sources, including the issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock, (iv) common stock and (v) other securities. We may also sell assets and issue securities in exchange for oil and natural gas assets or interests in oil and natural gas companies. Additional securities may be of a class senior to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as

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determined from time to time by our board of directors. Utilization of some of these financing sources may require approval from the lenders under our credit facility.

     On February 1, 2010, we issued approximately 5.3 million shares of our common stock at $42.75 per share in a public offering. After deducting underwriting discounts of approximately $9.1 million and transaction costs, we received net proceeds of approximately $219.3 million. The net proceeds from this offering were used to repay a portion of the borrowing under our credit facility.

     Financial markets.The current state of the financial markets remains uncertain; however, we have recently seen improvements in the stock market, and the credit markets appear to have stabilized. There have been financial institutions that have (i) failed and been forced into government receivership, (ii) received government bail-outs, (iii) declared bankruptcy, (iv) been forced to seek additional capital and liquidity to maintain viability or (v) merged. The United States and world economies have experienced and continue to experience volatility, which continues to impact the financial markets.

     At June 30, 2010, we had $852.0 million of available borrowing capacity. Our credit facility is backed by a syndicate of 20 banks. Even in light of the volatility in the financial markets, we believe that the lenders under our credit facility have the ability to fund additional borrowings we may need for our business.

     We pay floating rate interest under our credit facility, and we are unable to predict, especially in light of the uncertainty in the financial markets, whether we will incur increased interest costs due to rising interest rates. We have used interest rate derivatives to mitigate the cost of rising interest rates, and we may enter into additional interest rate derivatives in the future. Additionally, we may issue additional fixed rate debt in the future to increase available borrowing capacity under our credit facility or to reduce our exposure to the volatility of interest rates.

     In the current financial markets, there is no assurance that we could refinance our credit facility with comparable terms, particularly the five-year term of our credit facility. Because our credit facility matures in July 2013, we do not expect to seek refinancing of our credit facility any earlier than 2011.

     To the extent we need additional funds beyond those available under our credit facility to operate our business or make acquisitions, we would have to pursue other financing sources. These sources could include issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock, (iv) common stock or (v) other securities. We may also sell assets. However, in light of the current financial market conditions there are no assurances that we could obtain additional funding, or if available, at what cost and terms.

     Liquidity.Our principal sources of short-term liquidity are cash on hand and available borrowing capacity under our credit facility. At June 30, 2010, we had $0.4 million of cash on hand.

     At June 30, 2010, we had $852.0 million of available borrowing capacity. Our borrowing base is redetermined semi-annually, with the next redetermination occurring in October 2010. Between scheduled borrowing base redeterminations, we and, if requested by 66 2/3 percent of the lenders, the lenders, may each request one special redetermination. In general, redeterminations are based upon a number of factors, including commodity prices and reserve levels. Upon a redetermination, our borrowing base could be substantially reduced. In light of the current or the volatility in commodity prices and the state of the financial markets, there is no assurance that our borrowing base will not be reduced.

     As is customary in similar acquisitions, there may be adjustments payable to the seller to the purchase price for items such as (i) costs incurred after a specified date through the closing date, (ii) contractual preferential rights of third parties to purchase some of the assets involved in the transaction and (iii) other adjustments agreed to in the asset purchase agreement.

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     In addition, Marbob has contractual preferential rights under certain operating agreements to purchase certain interests in properties if third parties were to sell those interests in properties. BP announced it was selling all its assets in the Permian Basin to Apache. Marbob and BP own common interests in certain common properties subject to a contractual preferential right to purchase. BP and Apache have contested Marbob’s ability to exercise its contractual preferential rights in this situation. As a result, Marbob and we have filed suit against BP and Apache seeking declaratory judgment and injunctive relief to protect Marbob’s contractual right to have the option to purchase these interests in properties. We are unable to predict at this time if the court will grant Marbob and us the relief sought in connection with the suit.

     Currently, we have identified interests in properties in the Marbob Acquisition that we believe are subject to contractual preferential rights to purchase by third parties. If all the contractual preferential rights were exercised (including the approximately $400 million associated with BP), we estimate the purchase price would be reduced by approximately $500 million.

     As part of the Marbob Acquisition, we agreed to reimburse Marbob for drilling and completion costs, net of any revenues, incurred on specified properties from July 1, 2010 through the closing date. Though no assurances can be given, we are targeting an anticipated closing date of October 1, 2010. Assuming the Marbob Acquisition closes on October 1, 2010, we estimate we will be required to fund an additional $50 million of purchase price, which we believe we would fund under our credit facility.

     We intend to finance the $1.45 billion cash portion of the Marbob Acquisition with a combination of equity and debt. On July 19, 2010, we entered into a common stock purchase agreement with third-party investors to sell approximately 6.6 million shares of our common stock in a private placement for aggregate cash consideration of approximately $300 million. We anticipate that the private placement will close simultaneously with the Marbob Acquisition. We received an $800 million underwritten commitment from two of our lenders under the credit facility to expand the size of our existing credit facility from $1.2 billion to $2.0 billion as part of the financing for the Marbob Acquisition, which we expect will provide the credit capacity to fund the remaining cash portion of the purchase price. The expanded facility is expected to close simultaneously with the Marbob Acquisition. Assuming the transaction had closed on June 30, 2010 and no contractual preferential rights to purchase interests in properties had been exercised, we estimate we would have had approximately $400 million in availability under our expanded credit facility.

     Book capitalization and current ratio.Our book capitalization at June 30, 2010 was $2.4 billion, consisting of debt of $644.0 million and stockholders’ equity of $1.8 billion. Our debt to book capitalization was 27 percent and 39 percent at June 30, 2010 and December 31, 2009, respectively. Our ratio of current assets to current liabilities was 0.63 to 1.0 at June 30, 2010 as compared to 0.64 to 1.0 at December 31, 2009.

     Inflation and changes in prices.Our revenues, the value of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the six months ended June 30, 2010, we received an average of $74.81 per barrel of oil and $7.00 per Mcf of natural gas before consideration of commodity derivative contracts compared to $47.32 per barrel of oil and $4.52 per Mcf of natural gas in the six months ended June 30, 2009. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and continued through the first six months of 2008, commodity prices for oil and natural gas increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends have put pressure not only on our operating costs but also on capital costs. We expect these costs to have upward pressure during 2010 as a result of the recent improvements in oil prices from 2009.

Critical Accounting Policies, Practices and Estimates

     Our historical consolidated financial statements and related notes to consolidated financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to us.

     In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are revenue recognition, the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets and valuation of stock-based compensation. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates, as additional information becomes known.

     There have been no material changes in our critical accounting policies and procedures during the six months ended June 30, 2010. See our disclosure of critical accounting policies in the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 26, 2010.

Recent Accounting Pronouncements

     Various topics.In February 2010, the FASB issued an update to various topics, which eliminated outdated provisions and inconsistencies in the Accounting Standards Codification (the “Codification”), and clarified certain guidance to reflect the FASB’s original intent. The update is effective for the first reporting period, including interim periods, beginning after issuance of the update,

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except for the amendments affecting embedded derivatives and reorganizations. In addition to amending the Codification, the FASB made corresponding changes to the legacy accounting literature to facilitate historical research. These changes are included in an appendix to the update. We adopted the update effective January 1, 2010, and the adoption did not have a significant impact on our consolidated financial statements.

     Accounting for extractive activities.In April 2010, the FASB issued an amendment to a paragraph in the accounting standard for oil and natural gas extractive activities accounting. The standard adds to the Codification the SEC’sModernization of Oil and Gas Reportingrelease. We adopted the update effective April 20, 2010, and the adoption did not have a significant impact on our consolidated financial statements.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

     The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2009.

     We are exposed to a variety of market risks including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we are a party at June 30, 2010, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit. We do not enter into derivative or other financial instruments for speculative or trading purposes.

     Hypothetical changes in interest rates and commodity prices chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

     Credit risk.We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our oil and natural gas production, which we market to energy marketing companies and refineries and to a lesser extent our derivative counterparties. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Although we have not generally required our counterparties to provide collateral to support their obligation to us, we may, if circumstances dictate, require collateral in the future. In this manner, we could further reduce credit risk.

     Commodity price risk.We are exposed to market risk as the prices of oil and natural gas are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of oil and natural gas we have entered into, and may in the future enter into, additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a specified period of time. Our commodity price risk management activities could have the effect of reducing net income and the value of our common stock. An average increase in the commodity price of $10.00 per barrel of oil and $1.00 per MMBtu for natural gas from the commodity prices at June 30, 2010, would have created a net unrealized loss of approximately $121.8 million on our commodity price risk management contracts held at June 30, 2010.

     At June 30, 2010, we had (i) oil price swaps that settle on a monthly basis covering future oil production from July 1, 2010 through December 31, 2012 and (ii) a natural gas price swap, natural gas price collars and natural gas basis swaps covering future natural gas production from July 1, 2010 to December 31, 2012; see Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on our commodity derivative contracts. The average NYMEX oil futures price and average NYMEX natural gas futures price for the six months ended June 30, 2010, was $78.36 per Bbl and $4.69 per MMBtu, respectively. At August 4, 2010, the NYMEX oil price and NYMEX natural gas price were $82.47 per Bbl and $4.74 per MMBtu, respectively. A decrease in oil and natural gas prices would increase the fair value asset of our commodity derivative contracts from their recorded balance at June 30, 2010. Changes in the recorded fair value of the undesignated commodity derivative contracts are marked to market through earnings as unrealized gains or losses. The potential increase in our fair value asset would be recorded in earnings as an unrealized gain. However, an increase in the average NYMEX oil and natural gas prices above those at June 30, 2010, would result in a decrease in our fair value asset and be recorded as an unrealized loss in earnings. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.

     Interest rate risk.Our exposure to changes in interest rates relates primarily to debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. To reduce our exposure to changes in interest rates we have entered into, and may in the future enter into additional interest rate risk management arrangements for a portion of our outstanding debt. The agreements that we have entered into generally have the effect of providing us with a fixed interest rate for a portion of our variable rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We are exposed to changes in interest rates as a result of our credit facility, and the terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available borrowing base.

     At June 30, 2010, we had interest rate swaps on $300 million of notional principal that fixed the LIBOR interest rate (not including the interest rate margins discussed above) at 1.90 percent for the three years beginning in May 2009. An average decrease

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in future interest rates of 25 basis points from the future rate at June 30, 2010, would have increased our net unrealized liability on our interest rate risk management contracts by approximately $1.4 million.

     We had total indebtedness of $348.0 million outstanding under our credit facility at June 30, 2010. The impact of a 1 percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $3.5 million.

     The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method during 2010. During 2010, we were party to commodity and interest rate derivative instruments; see Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the six months ended June 30, 2010:

	Derivative Instruments Net Assets (Liabilities)(a)
(in thousands)	Commodities			Interest Rate			Total
Fair value of contracts outstanding at December 31, 2009	$	(64,332	)	$	(2,501	)	$	(66,833	)
Changes in fair values(b)		134,554			(6,218	)		128,336
Contract maturities		6,865			2,434			9,299
Fair value of contracts outstanding at June 30, 2010	$	77,087		$	(6,285	)	$	70,802

(a)	Represents the fair values of open derivative contracts subject to market risk.
(b)	At inception, new derivative contracts entered into by us have no intrinsic value.

Item 4. Controls and Procedures

     Evaluation of Disclosure Controls and Procedures.As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at June 30, 2010 at the reasonable assurance level.

     Changes in Internal Control over Financial Reporting.There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

     We are party to the legal proceedings that are described in Note K of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).” We are party to certain proceedings and claims incidental to our business. While many of these other matters involve inherent uncertainty, we believe that the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future results of operations.

Item 1A. Risk Factors

     In addition to the other information set forth in this Report, you should carefully consider the risks discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, under the headings “Item 1. Business – Competition, Marketing Arrangements and Applicable Laws and Regulations,” “Item 1A. Risk Factors” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” which risks could materially affect the Company’s business, financial condition or future results. Except for the risk factor set forth below, there have been no material changes in the Company’s risk factors from those described in its Annual Report on Form 10-K for the year ended December 31, 2009.

     Our estimates of proved reserves have been prepared under new SEC rules which went into effect for fiscal years ending on or after December 31, 2009, which may make comparisons to prior periods difficult and could limit our ability to book additional proved undeveloped reserves in the future.

     Our Annual Report on Form 10-K for the year ended December 31, 2009 presents estimates of our proved reserves as of December 31, 2009, which have been prepared and presented under new SEC rules. These new rules are effective for fiscal years ending on or after December 31, 2009, and require SEC reporting companies to prepare their reserves estimates using revised reserve definitions and revised pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The previous rules required that reserve estimates be calculated using last-day-of-the-year pricing. The pricing that was used for estimates of our reserves as of December 31, 2009 was based on an unweighted average twelve month West Texas Intermediate posted price of $57.65 per Bbl for oil and a Henry Hub spot natural gas price of $3.87 per MMBtu for natural gas. As a result of this change in pricing methodology, direct comparisons of our previously-reported reserves amounts may be more difficult.

     Another impact of the new SEC rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule has limited and may continue to limit our potential to book additional proved undeveloped reserves as we pursue our drilling program, particularly as we develop our significant acreage in West Texas and Southeast New Mexico. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill on those reserves within the required five-year timeframe.

     Accordingly, while the estimates of our proved reserves and related PV-10 and Standardized Measure at December 31, 2009 included in our Annual Report on Form 10-K for the year ended December 31, 2009 were prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the new SEC rules, those estimates could differ materially from any estimates we might prepare applying future interpretive guidance from the SEC.

     The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

     The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including

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through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

					Total number		Maximum
					of shares		number of
					purchased as		shares that
	Total number				part of publicly		may yet be
	of shares		Average price		announced		purchased
Period	withheld(1)		per share		plans		under the plan
April 1, 2010 - April 30, 2010		—	$	—		—
May 1, 2010 - May 31, 2010		1,603	$	46.79		—
June 1, 2010 - June 30, 2010		5,005	$	58.17		—

⁽¹⁾ Represents shares that were withheld by us to satisfy tax withholding obligations of certain of our officers, directors and key employees that arose upon the lapse of restrictions on restricted stock.

Item 5. Other Information

     We are filing a revised report from Cawley, Gillespie & Associates, Inc. (“Cawley”), our independent petroleum engineers, included in Exhibit 23.2 to this Quarterly Report on Form 10-Q, which is a letter dated January 25, 2010 regarding proved reserves. The Cawley report filed as Exhibit 23.4 to our Annual Report on Form 10-K contained the following language, which has been deleted in the Cawley report filed as Exhibit 23.2 to this Quarterly Report on Form 10-Q: “This letter was prepared for the exclusive use of Concho Resources Inc. Third parties should not rely on it without the written consent of the above and Cawley, Gillespie & Associates, Inc.” Other than this change, there has been no other change to the Cawley report filed as Exhibit 23.2 to this Quarterly Report on Form 10-Q.

     We are also filing an updated consent of Cawley, Gillespie & Associates, Inc. as Exhibit 23.1, to this Quarterly Report on Form 10-Q.

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Item 6. Exhibits

Exhibit
Number	Exhibit
2.1 *	Asset Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc., Marbob Energy Corporation, Pitch Energy Corporation, Costaplenty Energy Corporation and John R. Gray, LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on July 20, 2010, and incorporated herein by reference).
3.1	Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).
3.2	Amended and Restated Bylaws of Concho Resources Inc., as amended March 25, 2008 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on March 26, 2008, and incorporated herein by reference).
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Current Report on Form S-1/A on July 5, 2007, and incorporated herein by reference).
10.1	Second Amendment to Amended and Restated Credit Agreement, dated April 26, 2010, by and among Concho Resources Inc., JP Morgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 29, 2010, and incorporated herein by reference).
10.2	Third Amendment to Amended and Restated Credit Agreement and Limited Waiver, dated June 16, 2010, among Concho Resources Inc. and the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 18, 2010, and incorporated herein by reference).
10.3	Common Stock Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc. and the purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on July 20, 2010, and incorporated herein by reference).
23.1 (a)	Consent of Cawley, Gillespie & Associates, Inc.
23.2 (a)	Cawley, Gillespie & Associates, Inc. Reserve Report.
31.1 (a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 (a)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 (b)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 (b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS (a)	XBRL Instance Document.
101.SCH (a)	XBRL Schema Document.
101.CAL (a)	XBRL Calculation Linkbase Document.
101.DEF (a)	XBRL Definition Linkbase Document.
101.LAB (a)	XBRL Labels Linkbase Document.
101.PRE (a)	XBRL Presentation Linkbase Document.

(a)	Filed herewith.
(b)	Furnished herewith.
*	The schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S-K. The Company will furnish copies of such schedules to the Securities and Exchange Commission upon request.

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SIGNATURES

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

	CONCHO RESOURCES INC.
Date: August 6, 2010	By	/s/ Timothy A. Leach
		Timothy A. Leach
		Director, Chairman of the Board of Directors, Chief Executive Officer and President (Principal Executive Officer)
	By	/s/ Darin G. Holderness
		Darin G. Holderness
		Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)

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EXHIBIT INDEX

Exhibit
Number	Exhibit
2.1 *	Asset Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc., Marbob Energy Corporation, Pitch Energy Corporation, Costaplenty Energy Corporation and John R. Gray, LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on July 20, 2010, and incorporated herein by reference).
3.1	Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).
3.2	Amended and Restated Bylaws of Concho Resources Inc., as amended March 25, 2008 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on March 26, 2008, and incorporated herein by reference).
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Current Report on Form S-1/A on July 5, 2007, and incorporated herein by reference).
10.1	Second Amendment to Amended and Restated Credit Agreement, dated April 26, 2010, by and among Concho Resources Inc., JP Morgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 29, 2010, and incorporated herein by reference).
10.2	Third Amendment to Amended and Restated Credit Agreement and Limited Waiver, dated June 16, 2010, among Concho Resources Inc. and the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 18, 2010, and incorporated herein by reference).
10.3	Common Stock Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc. and the purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on July 20, 2010, and incorporated herein by reference).
23.1 (a)	Consent of Cawley, Gillespie & Associates, Inc.
23.2 (a)	Cawley, Gillespie & Associates, Inc. Reserve Report.
31.1 (a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 (a)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 (b)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 (b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS (a)	XBRL Instance Document.
101.SCH (a)	XBRL Schema Document.
101.CAL (a)	XBRL Calculation Linkbase Document.
101.DEF (a)	XBRL Definition Linkbase Document.
101.LAB (a)	XBRL Labels Linkbase Document.
101.PRE (a)	XBRL Presentation Linkbase Document.

(a)	Filed herewith.
(b)	Furnished herewith.
*	The schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S-K. The Company will furnish copies of such schedules to the Securities and Exchange Commission upon request.