Edgar Filing: CONCHO RESOURCES INC

e10vq

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 March 31, 2010


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		(I.R.S. Employer
of incorporation or organization)		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. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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). Yes o No o

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


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

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

Number of shares of the registrant’s common stock outstanding at May 5, 2010: 91,548,943 shares.

TABLE OF CONTENTS


PART I – FINANCIAL INFORMATION	iii
Item 1. Consolidated Financial Statements (Unaudited)	iii
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		37
Item 3. Quantitative and Qualitative Disclosures About Market Risk		50
Item 4. Controls and Procedures		51
PART II – OTHER INFORMATION		52
Item 1. Legal Proceedings		52
Item 1A. Risk Factors		52
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		52
Item 6. Exhibits		53
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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 may include projections and estimates concerning capital expenditures, our liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of our business strategy and other statements concerning our operations, economic performance and financial condition. 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. 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. 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, including uncertainties associated with the United States Securities and Exchange Commission’s (the “SEC”) new rules governing oil and natural gas reserve reporting;

	•		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;

	•		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;

	•		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.

PART I – FINANCIAL INFORMATION


*Item 1.*		*Consolidated Financial Statements (Unaudited)*


Consolidated Balance Sheets at March 31, 2010 and December 31, 2009			1

Consolidated Statements of Operations for the Three Months Ended March 31, 2010 and 2009			2

Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2010			3

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009			4

Condensed Notes to Consolidated Financial Statements			5

iii

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited


	March 31,			December 31,
(in thousands, except share and per share data)	2010			2009

Assets
Current assets:
Cash and cash equivalents	$	6,988		$	3,234
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas		94,886			69,199
Joint operations and other		86,356			100,120
Related parties		407			216
Derivative instruments		9,078			1,309
Deferred income taxes		18,316			29,284
Prepaid costs and other		9,785			13,896

Total current assets		225,816			217,258

Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		3,508,322			3,358,004
Accumulated depletion and depreciation		(572,562	)		(517,421	)

Total oil and natural gas properties, net		2,935,760			2,840,583
Other property and equipment, net		15,976			15,706

Total property and equipment, net		2,951,736			2,856,289

Deferred loan costs, net		19,636			20,676
Inventory		19,758			16,255
Intangible asset, net — operating rights		36,135			36,522
Noncurrent derivative instruments		26,979			23,614
Other assets		473			471

Total assets	$	3,280,533		$	3,171,085

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	5,702		$	15,443
Related parties		348			291
Other current liabilities:
Bank overdrafts		—			3,415
Revenue payable		39,169			31,069
Accrued and prepaid drilling costs		192,540			164,282
Derivative instruments		55,329			62,419
Other current liabilities		73,478			60,095

Total current liabilities		366,566			337,014

Long-term debt		625,928			845,836
Noncurrent derivative instruments		21,148			29,337
Deferred income taxes		616,649			603,286
Asset retirement obligations and other long-term liabilities		19,205			20,184
Commitments and contingencies (Note K)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 91,555,423 and 85,815,926 shares issued at March 31, 2010 and December 31, 2009, respectively		92			86
Additional paid-in capital		1,257,674			1,029,392
Retained earnings		373,907			306,367
Treasury stock, at cost; 17,059 and 12,380 shares at March 31, 2010 and December 31, 2009, respectively		(636	)		(417	)

Total stockholders’ equity		1,631,037			1,335,428

Total liabilities and stockholders’ equity	$	3,280,533		$	3,171,085

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

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited


	Three Months Ended March 31,
(in thousands, except per share amounts)	2010			2009

Operating revenues:
Oil sales	$	162,725			$	64,974
Natural gas sales		49,275				21,028

Total operating revenues		212,000				86,002

Operating costs and expenses:
Oil and natural gas production		36,700				24,766
Exploration and abandonments		1,295				5,995
Depreciation, depletion and amortization		53,843				50,748
Accretion of discount on asset retirement obligations		400				278
Impairments of long-lived assets		2,620				4,056
General and administrative (including non-cash stock-based compensation of $2,831 and $1,925 for the three months ended March 31, 2010 and 2009, respectively)		13,558				11,746
Bad debt expense		539				—
(Gain) loss on derivatives not designated as hedges		(15,573	)			5,046

Total operating costs and expenses		93,382				102,635

Income (loss) from operations		118,618				(16,633	)

Other income (expense):
Interest expense		(11,065	)			(4,370	)
Other, net		(73	)			(328	)

Total other expense		(11,138	)			(4,698	)

Income (loss) before income taxes		107,480				(21,331	)
Income tax benefit (expense)		(39,940	)			8,106

Net income (loss)	$	67,540			$	(13,225	)

Basic earnings per share:
Net income (loss) per share	$	0.76			$	(0.16	)

Weighted average shares used in basic earnings per share		88,831				84,529

Diluted earnings per share:
Net income (loss) per share	$	0.75			$	(0.16	)

Weighted average shares used in diluted earnings per share		90,130				84,529

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

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		—			—		—		67,540		—		—			67,540
Issuance of common stock		5,348			5		219,456		—		—		—			219,461
Stock options exercised		248			1		2,497		—		—		—			2,498
Stock-based compensation for restricted stock		145			—		1,822		—		—		—			1,822
Cancellation of restricted stock		(2	)		—		—		—		—		—			—
Stock-based compensation for stock options		—			—		1,009		—		—		—			1,009
Excess tax benefits related to stock-based compensation		—			—		3,498		—		—		—			3,498
Purchase of treasury stock		—			—		—		—		5		(219	)		(219	)

BALANCE AT MARCH 31, 2010		91,555		$	92	$	1,257,674	$	373,907		17	$	(636	)	$	1,631,037

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

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited


	Three Months Ended March 31,
(in thousands)	2010			2009

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	67,540		$	(13,225	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		53,843			50,748
Impairments of long-lived assets		2,620			4,056
Accretion of discount on asset retirement obligations		400			278
Exploration and abandonments, including dry holes		627			5,318
Non-cash compensation expense		2,831			1,925
Bad debt expense		539			—
Deferred income taxes		27,829			(10,871	)
(Gain) loss on sale of assets		(17	)		243
(Gain) loss on derivatives not designated as hedges		(15,573	)		5,046
Other non-cash items		1,140			813
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		(15,963	)		(31,744	)
Prepaid costs and other		5,372			1,581
Inventory		(3,508	)		(2,371	)
Accounts payable		(9,752	)		15,203
Revenue payable		8,100			2,273
Other current liabilities		11,199			11,339

Net cash provided by operating activities		137,227			40,612

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and natural gas properties		(113,722	)		(131,559	)
Acquisition of oil and natural gas properties		(10,356	)		—
Additions to other property and equipment		(1,168	)		(1,078	)
Proceeds from the sale of oil and natural gas properties and other assets		790			1,000
Settlements received from (paid on) derivatives not designated as hedges		(10,840	)		37,124

Net cash used in investing activities		(135,296	)		(94,513	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		109,500			100,650
Payments of long-term debt		(329,500	)		(59,900	)
Net proceeds from issuance of common stock		219,461			—
Exercise of stock options		2,498			2,005
Excess tax benefit from stock-based compensation		3,498			804
Purchase of treasury stock		(219	)		—
Bank overdrafts		(3,415	)		(5,003	)

Net cash provided by financing activities		1,823			38,556

Net increase (decrease) in cash and cash equivalents		3,754			(15,345	)
Cash and cash equivalents at beginning of period		3,234			17,752

Cash and cash equivalents at end of period	$	6,988		$	2,407

SUPPLEMENTAL CASH FLOWS:
Cash paid for interest and fees, net of $18 and $15 capitalized interest	$	3,729		$	3,457
Cash paid for income taxes	$	9,808		$	1,065

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

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

Note A. Organization and nature of operations

Concho Resources Inc. (the “Company”) 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 are 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, the 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 March 31, 2010, its results of operations and its cash flows for the three months ended March 31, 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 $19.6 million and $20.7 million, net of accumulated amortization of $9.6 million and $8.6 million, at March 31, 2010 and December 31, 2009, respectively.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

Future amortization expense of deferred loan costs at March 31, 2010 is as follows:


(in thousands)

Remaining 2010	$	3,150
2011		4,266
2012		4,350
2013		3,021
2014		1,132
Thereafter		3,717

Total	$	19,636

Intangible assets. The Company has capitalized certain operating rights acquired in 2008. The gross operating rights of approximately $38.7 million and related accumulated amortization of $2.6 million, 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. Amortization expense for both of the three months ended March 31, 2010 and 2009 was approximately $0.4 million. The following table reflects the estimated aggregate amortization expense for each of the periods presented below:


(in thousands)

Remaining 2010	$	1,162
2011		1,549
2012		1,549
2013		1,549
2014		1,549
Thereafter		28,777

Total	$	36,135

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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

The following table reflects the Company’s natural gas imbalance positions at March 31, 2010 and December 31, 2009 as well as amounts reflected in oil and natural gas production expense for the three months ended March 31, 2010 and 2009:


	March 31,		December 31,
(dollars in thousands)	2010		2009

Natural gas imbalance receivable (included in other assets)	$	446	$	444
Undertake position (Mcf)		99,016		98,584

Natural gas imbalance liability (included in asset retirement obligations and other long-term liabilities)	$	530	$	533
Overtake position (Mcf)		100,426		101,278


	Three Months Ended March 31,
	2010			2009

Value of net overtake (undertake) arising during the period increasing (decreasing) oil and natural gas production expense	$	(5	)	$	49
Net overtake (undertake) position arising during the period (Mcf)		(1,284	)		11,766

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 $2.9 million and $2.7 million for the three months ended March 31, 2010 and 2009, respectively.

Recent accounting pronouncements. 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, 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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

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 months ended March 31, 2010:


	Three Months Ended
(in thousands)	March 31, 2010

Beginning capitalized exploratory well costs	$	8,668
Additions to exploratory well costs pending the determination of proved reserves		30,335
Reclassifications due to determination of proved reserves		(14,686	)
Exploratory well costs charged to expense		—

Ending capitalized exploratory well costs	$	24,317

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


	March 31,		December 31,
(in thousands)	2010		2009

Wells in drilling progress	$	6,378	$	1,767
Capitalized exploratory well costs that have been capitalized for a period of one year or less		17,939		6,901
Capitalized exploratory well costs that have been capitalized for a period greater than one year		—		—

Total capitalized exploratory well costs	$	24,317	$	8,668

At March 31, 2010, the Company had 26 gross exploratory wells waiting on their completion, including 10 wells in the Texas Permian area, 11 wells in the New Mexico Permian area and 5 wells in the Williston Basin of North Dakota.

Note D. Acquisitions

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, subject to usual and customary post-closing adjustments. 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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

The following tables represent 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.

The following table summarizes the Company’s asset retirement obligation transactions recorded during the three months ended March 31, 2010 and 2009:


	Three Months Ended March 31,
(in thousands)	2010			2009

Asset retirement obligations, beginning of period	$	22,754		$	16,809
Liabilities incurred from new wells		446			168
Accretion expense		400			278
Disposition of wells		—			(142	)
Liabilities settled upon plugging and abandoning wells		(185	)		(10	)
Revision of estimates		(2,578	)		1,151

Asset retirement obligations, end of period	$	20,837		$	18,254

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 $219.5 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 executive officers lapsed during the three months ended March 31, 2010. Immediately upon the lapse of restrictions, these executive officers 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

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

stock award agreements, some of such officers 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 March 31, 2010 and December 31, 2009, the Company had acquired 17,059 and 12,380 shares, respectively, that are held as treasury stock in the approximate amounts of $636,000 and $417,000, 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. 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 March 31, 2010 and 2009 were approximately $0.2 million and $0.3 million, respectively.

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 March 31, 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		(948,136	)

Awards available for future grant		1,438,144

Restricted stock awards. All restricted shares are treated as issued and outstanding in the accompanying consolidated balance sheets. If an employee terminates employment prior the restriction lapse date, the awarded shares 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 three months ended March 31, 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		144,801		$	45.52
Shares cancelled / forteited		(1,719	)
Lapse of restrictions		(42,523	)

Outstanding at March 31, 2010		597,816

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

The following table summarizes information about stock-based compensation for the Company’s restricted stock awards for the three months ended March 31, 2010 and 2009:


	Three Months Ended March 31,
(in thousands)	2010		2009

*Grant date fair value for awards during the period:*
Employee grants	$	1,590	$	—
Officer and director grants		5,075		1,850

Total	$	6,665	$	1,850


*Stock-based compensation expense from restricted stock:*
Employee grants	$	978	$	563
Officer and director grants		844		334

Total	$	1,822	$	897


*Income taxes and other information:*
Income tax benefit related to restricted stock	$	689	$	341
Deductions in current taxable income related to restricted stock	$	1,707	$	378

Stock option awards. A summary of the Company’s stock option awards activity under the Plan for the three months ended March 31, 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		(248,915	)	$	10.03

Outstanding at March 31, 2010		1,907,588		$	14.64


Vested at end of period		1,347,376		$	12.24


Exercisable at end of period		935,160		$	14.03

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

The following table summarizes information about the Company’s vested and exercisable stock options outstanding at March 31, 2010:


					Weighted
					Average	Weighted
			Number		Remaining	Average
			of Stock		Contractual	Exercise		Intrinsic
			Options		Life	Price		Value
								(in thousands)
*Vested options:*

March 31, 2010:
Exercise price	$	8.00		782,753	1.86 years	$	8.00	$	33,157
Exercise price	$	12.00		103,854	4.56 years	$	12.00		3,984
Exercise price	$	14.62		188,750	6.57 years	$	14.62		6,745
Exercise price	$	21.67		240,328	8.05 years	$	21.67		6,895
Exercise price	$	32.03		31,691	8.26 years	$	32.03		581

				1,347,376	3.98 years	$	12.24	$	51,362


*Exercisable options:*

March 31, 2010:
Exercise price	$	8.00		388,365	1.98 years	$	8.00	$	16,451
Exercise price	$	12.00		86,026	5.14 years	$	12.00		3,300
Exercise price	$	14.62		188,750	6.57 years	$	14.62		6,745
Exercise price	$	21.67		240,328	8.05 years	$	21.67		6,895
Exercise price	$	32.03		31,691	8.26 years	$	32.03		581

				935,160	4.97 years	$	14.03	$	33,972

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

The following table summarizes information about stock-based compensation for stock options for the three months ended March 31, 2010 and 2009:


	Three Months Ended March 31,
(in thousands)	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	$	44	$	71
Officer and director grants		965		957

Total	$	1,009	$	1,028


*Income taxes and other information:*
Income tax benefit related to stock options	$	381	$	391
Deductions in current taxable income related to stock options exercised	$	9,651	$	3,040

The Company used the simplified method that is accepted by the SEC to calculate the expected term for stock options granted during the three months ended March 31, 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 at March 31, 2010 is summarized in the table below:


	Restricted		Stock
(in thousands)	Stock		Options		Total

Remaining 2010	$	6,012	$	1,643	$	7,655
2011		4,331		879		5,210
2012		1,669		184		1,853
2013		454		15		469
2014		48		1		49

Total	$	12,514	$	2,722	$	15,236

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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 March 31, 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		March 31,
(in thousands)	(Level 1)		(Level 2)			(Level 3)		2010

Assets:
Commodity derivative price swap contracts	$	—	$	66,850		$	—	$	66,850
Commodity derivative price collar contracts		—		—			6,961		6,961

		—		66,850			6,961		73,811

Liabilities:
Commodity derivative price swap contracts		—		(100,913	)		—		(100,913	)
Commodity derivative basis swap contracts		—		(8,605	)		—		(8,605	)
Interest rate derivative swap contracts		—		(4,713	)		—		(4,713	)

		—		(114,231	)		—		(114,231	)


Net financial assets (liabilities)	$	—	$	(47,381	)	$	6,961	$	(40,420	)

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		7,996
Settlements (receipts), net		(90	)

Balance at March 31, 2010	$	6,961


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	$	7,906

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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 March 31, 2010 and December 31, 2009:


	March 31, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
(in thousands)	Value		Value		Value		Value

Assets:
Derivative instruments	$	36,057	$	36,057	$	24,923	$	24,923

Liabilities:
Derivative instruments	$	76,477	$	76,477	$	91,756	$	91,756
Credit facility	$	330,000	$	319,463	$	550,000	$	528,849
8.625% senior notes due 2017	$	295,928	$	318,000	$	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 are based on quoted market prices.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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 table (i) summarizes the valuation of each of the Company’s financial instruments by required pricing levels and (ii) summarizes 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 March 31, 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		March 31,
(in thousands)	(Level 1)		(Level 2)			(Level 3)		2010

Assets ⁽¹⁾
Current: ^(a)
Commodity derivative price swap contracts	$	—	$	25,976		$	—	$	25,976
Commodity derivative price collar contracts		—		—			6,961		6,961

		—		25,976			6,961		32,937
Noncurrent: ^(b)
Commodity derivative price swap contracts		—		40,874			—		40,874
Interest rate derivative swap contracts		—		—			—		—

		—		40,874			—		40,874

Liabilities ⁽¹⁾
Current: ^(a)
Commodity derivative price swap contracts		—		(69,307	)		—		(69,307	)
Commodity derivative basis swap contracts		—		(5,675	)		—		(5,675	)
Interest rate derivative swap contracts		—		(4,206	)		—		(4,206	)

		—		(79,188	)		—		(79,188	)
Noncurrent: ^(b)
Commodity derivative price swap contracts		—		(31,606	)		—		(31,606	)
Commodity derivative basis swap contracts		—		(2,930	)		—		(2,930	)
Interest rate derivative swap contracts		—		(507	)		—		(507	)

		—		(35,043	)		—		(35,043	)

Net financial assets (liabilities)	$	—	$	(47,381	)	$	6,961	$	(40,420	)


(a) Total current financial assets (liabilities), gross basis								$	(46,251	)
(b) Total noncurrent financial assets (liabilities), gross basis									5,831

Net financial assets (liabilities)								$	(40,420	)

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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 assets (liabilities)	$	—	$	(65,888	)	$	(945	)	$	(66,833	)


(a) Total current financial assets (liabilities), gross basis									$	(61,110	)
(b) Total noncurrent financial assets (liabilities), gross basis										(5,723	)

Net financial assets (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 March 31, 2010 and December 31, 2009:

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited


	March 31,			December 31,
(in thousands)	2010			2009

Consolidated Balance Sheet Classification:

Current derivative contracts:
Assets	$	9,078		$	1,309
Liabilities		(55,329	)		(62,419	)

Net current	$	(46,251	)	$	(61,110	)


Noncurrent derivative contracts:
Assets	$	26,979		$	23,614
Liabilities		(21,148	)		(29,337	)

Net noncurrent	$	5,831		$	(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 of $2.4 million and $4.1 million for the three months ended March 31, 2010 and 2009, respectively, 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 months ended March 31, 2010 and 2009:


	Carrying		Estimated		Impairment
(in thousands)	Amount		Fair Value		Expense

Three months ended March 31, 2010	$	5,892	$	3,272	$	2,620

Three months ended March 31, 2009	$	6,943	$	2,887	$	4,056

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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

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 March 31, 2010:
Impairment of long-lived assets	$	—	$	—	$	3,272	$	(2,620	)
Asset retirement obligations incurred in current period		—		—		446

Three months ended March 31, 2009:
Impairment of long-lived assets	$	—	$	—	$	2,887	$	(4,056	)
Asset retirement obligations incurred in current period		—		—		168

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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

New commodity derivative contracts in the first quarter of 2010. During the three months ended March 31, 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		792,000	$	81.77	^(a)		1/1/11 - 12/31/11
Price swap		168,000	$	89.00	^(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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

Commodity derivative contracts at March 31, 2010. The following table sets forth the Company’s outstanding commodity derivative contracts at March 31, 2010:


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total

Oil Swaps: ^(a)
*2010:*
Volume (Bbl)				1,387,936		1,263,936		1,172,936		3,824,808
Price per Bbl			$	71.81	$	71.59	$	71.42	$	71.61
*2011:*
Volume (Bbl)		1,042,436		1,003,436		968,436		936,436		3,950,744
Price per Bbl	$	78.10	$	78.30	$	78.49	$	78.68	$	78.38
*2012:*
Volume (Bbl)		168,000		168,000		168,000		168,000		672,000
Price per Bbl	$	118.10	$	118.10	$	118.10	$	118.10	$	118.10

Natural Gas Swaps: ^(b)
*2010:*
Volume (MMBtu)				2,647,000		2,427,000		2,258,000		7,332,000
Price per MMBtu			$	6.03	$	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		1,500,000		4,500,000
Price per MMBtu			$	5.25 - $5.75	$	5.25 - $5.75	$	6.00 - $6.80	$	5.50 - $6.10
*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		2,100,000		6,300,000
Price per MMBtu			$	0.85	$	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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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 of 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:


	Three Months Ended March 31,
(in thousands)	2010			2009

*Gain (loss) on derivatives not designated as hedges:*
Cash (payments on) receipts from derivatives not designated as hedges:
Commodity derivatives:
Oil	$	(10,133	)	$	34,584
Natural gas		506			2,540
Interest rate derivatives		(1,213	)		—

Mark-to-market gain (loss):
Commodity derivatives:
Oil		1,438			(39,037	)
Natural gas		27,187			(706	)
Interest rate derivatives		(2,212	)		(2,427	)

Total gain (loss) on derivatives not designated as hedges	$	15,573		$	(5,046	)

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

Second quarter 2010 commodity derivative contracts. In April 2010, the Company entered into the following oil price swaps to hedge an additional portion of its estimated future production:

Aggregate

Index

Contract

Volume

Price

Period

Oil (volumes in Bbls):

Price swap

1,463,000

88.63

^(a)

5/1/10 - 12/31/10

Price swap

1,344,000

92.25

^(a)

1/1/11 - 12/31/11

Price swap

2,040,000

92.98

^(a)

1/1/12 - 12/31/12


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

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

Note J. Debt

The Company’s debt consisted of the following:


	March 31,			December 31,
(in thousands)	2010			2009

Credit facility	$	330,000		$	550,000
8.625% unsecured senior notes due 2017		300,000			300,000
Less: unamortized original issue discount		(4,072	)		(4,164	)
Less: current portion		—			—

Total long-term debt	$	625,928		$	845,836

Credit facility. The Company’s credit facility, as amended, (the “Credit Facility”) has a maturity date of July 31, 2013. At March 31, 2010, the Company had letters of credit outstanding under the Credit Facility of approximately $25,000, and its availability to borrow additional funds was approximately $625.9 million based on its borrowing base at the time of $955.9 million. In April 2010, the lenders increased the Company’s borrowing base to $1.2 billion until the next scheduled borrowing base redetermination 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.

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 March 31, 2010) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). At March 31, 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 March 31, 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 this 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 agreement 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 March 31, 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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

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 March 31, 2010, the Company was in compliance with its covenants in the indenture.

Future interest expense from the original issue discount at March 31, 2010 is as follows:


(in thousands)

Remaining 2010	$	292
2011		421
2012		462
2013		507
2014		557
Thereafter		1,833

Total	$	4,072

Principal maturities of debt. Principal maturities of debt outstanding at March 31, 2010 are as follows:


(in thousands)

2010	$	—
2011		—
2012		—
2013		330,000
2014 and thereafter		300,000

Total	$	630,000

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

Interest expense. The following amounts have been incurred and charged to interest expense for the three months ended March 31, 2010 and 2009:


	Three Months Ended March 31,
(in thousands)	2010			2009

Cash payments for interest	$	3,747		$	3,472
Amortization of original issue discount		92			—
Amortization of deferred loan origination costs		1,040			856
Net changes in accruals		6,204			57

Interest costs incurred		11,083			4,385
Less: capitalized interest		(18	)		(15	)

Total interest expense	$	11,065		$	4,370

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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.

Indemnifications. 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 March 31, 2010 and 2009, the Company recognized $2.5 million and $2.6 million, respectively, of this obligation in its results of operations.

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 March 31, 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)		421		421		—		—		—

Total contractual drilling commitments	$	1,421	$	1,421	$	—	$	—	$	—


^(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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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 March 31, 2010 and 2009 were approximately $591,000 and $671,000, respectively. Future minimum lease commitments under non-cancellable operating leases at March 31, 2010 are as follows:


(in thousands)

Remaining 2010	$	1,700
2011		1,734
2012		1,299
2013		1,170
2014 and thereafter		3,518

Total	$	9,421

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 March 31, 2010, the Company had no valuation allowances related to its deferred tax assets.

At March 31, 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.

The Company’s provision for income taxes differed from the U.S. statutory rate of 35 percent primarily due to state income taxes and non-deductible expenses. The effective income tax rate for the three months ended March 31, 2010 and 2009 was 37.2 percent and 38.0 percent, respectively.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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 months ended March 31, 2010 and 2009:


	Three Months Ended March 31,
(in thousands)	2010			2009

Income (loss) from operations	$	39,940		$	(8,106	)

Changes in stockholders’ equity:
Excess tax benefits related to stock-based compensation		(3,498	)		(804	)

	$	36,442		$	(8,910	)

The Company’s income tax provision (benefit) attributable to income (loss) from operations consisted of the following for the three months ended March 31, 2010 and 2009:


	Three Months Ended March 31,
(in thousands)	2010		2009

*Current:*
U.S. federal	$	10,878	$	2,438
U.S. state and local		1,233		327

		12,111		2,765

*Deferred:*
U.S. federal		24,681		(9,585	)
U.S. state and local		3,148		(1,286	)

		27,829		(10,871	)

	$	39,940	$	(8,106	)

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 March 31,
(in thousands)	2010			2009

Income (loss) at U.S. federal statutory rate	$	37,618		$	(7,466	)
State income taxes (net of federal tax effect)		2,848			(623	)
Statutory depletion		(223	)		—
Nondeductible expense & other		(303	)		(17	)

Income tax expense (benefit)	$	39,940		$	(8,106	)

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

Note M. Related parties

Consulting Agreement. 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.

Mack Energy Corporation transactions. The Company incurred charges from Mack Energy Corporation (“MEC”), an affiliate of Chase Oil Corporation (“Chase Oil”), a stockholder of the Company, of approximately $0.4 million and $0.3 million for the three months ended March 31, 2010 and 2009, respectively, for services rendered in the ordinary course of business.

The Company had $113,000 and $87,000 in outstanding receivables due from MEC at March 31, 2010 and December 31, 2009, respectively, which are reflected in accounts receivable — related parties in the accompanying consolidated balance sheets. The Company had no outstanding payables to MEC at March 31, 2010 and $9,000 in outstanding payables to MEC at December 31, 2009, which are reflected in accounts payable — related parties in the accompanying consolidated balance sheets.

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% of the system and Chase Oil and its affiliates owned 2.5%.

Other related party transactions. The Company also has engaged in transactions with certain other affiliates of Chase Oil, 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 Company incurred charges from these related party vendors of approximately $4.0 million and $6.4 million for the three months ended March 31, 2010 and 2009, respectively.

The Company had no outstanding invoices payable to the other related party vendors identified above at March 31, 2010 or December 31, 2009.

Overriding royalty and royalty interests. Certain affiliates of Chase Oil own overriding royalty interests in certain of the Company’s properties. The amount paid attributable to such interests was approximately $0.5 million and $0.2 million for the three months ended March 31, 2010 and 2009, respectively. The Company owed royalty payments of approximately $301,000 and $80,000 to these affiliates of Chase Oil at March 31, 2010 and December 31, 2009, respectively. These amounts are reflected in accounts payable — related parties in the accompanying consolidated balance sheets.

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 Company paid approximately $41,000 and $26,000 for the three months ended March 31, 2010 and 2009, respectively. The Company owed this partnership royalty payments of approximately $12,000 at both March 31, 2010 and December 31, 2009. These amounts are reflected in accounts payable — related parties in the accompanying consolidated balance sheets.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

Working interests owned by employees. The Company purchased oil and natural gas properties from third parties in which employees of the Company owned a working interest. The following table summarizes the Company’s activities with these employees:


	Three Months Ended March 31,
(in thousands)	2010		2009

Revenues distributed to employees	$	78	$	30
Joint interest payments received from employees	$	230	$	639


	March 31,		December 31,
	2010		2009
Amounts included in accounts receivable — related parties	$	172	$	128
Amounts included in accounts payable — related parties	$	15	$	13

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 months ended March 31, 2010 and 2009:


	Three Months Ended March 31,
(in thousands)	2010		2009

*Weighted average common shares outstanding:*
Basic		88,831		84,529
Dilutive capital options		558		—
Dilutive common stock options		404		—
Dilutive restricted stock		337		—

Diluted		90,130		84,529

For the three months ended March 31, 2009, all shares were antidilutive due to the Company’s net loss. For the three months ended March 31, 2009, 484,376 shares of restricted stock and 2,600,769 stock options were not included in the computation of diluted loss per share, as inclusion of these items would be antidilutive.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

Note O. Other current liabilities

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


	March 31,		December 31,
(in thousands)	2010		2009

*Other current liabilities:*
Accrued production costs	$	26,880	$	24,128
Payroll related matters		14,742		14,490
Accrued interest		16,258		10,055
Asset retirement obligations		2,332		3,262
Settlements due on derivatives not designated as hedges		4,672		—
Other		8,594		8,160

Other current liabilities	$	73,478	$	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 March 31, 2010 and December 31, 2009, and Condensed Consolidating Statements of Operations and Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

Condensed Consolidating Balance Sheet
March 31, 2010


	Parent		Subsidiary		Consolidating
(in thousands)	Issuer		Guarantors		Entries			Total

ASSETS
Accounts receivable — related parties	$	3,880,804	$	2,469,257	$	(6,349,654	)	$	407
Other current assets		27,447		197,962		—			225,409
Total oil and natural gas properties, net		—		2,935,760		—			2,935,760
Total property and equipment, net		—		15,976		—			15,976
Investment in subsidiaries		978,756		—		(978,756	)		—
Total other long-term assets		46,615		56,366		—			102,981

Total assets	$	4,933,622	$	5,675,321	$	(7,328,410	)	$	3,280,533


LIABILITIES AND EQUITY
Accounts payable — related parties	$	1,968,955	$	4,381,047	$	(6,349,654	)	$	348
Other current liabilities		72,630		293,588		—			366,218
Other long-term liabilities		635,072		21,930		—			657,002
Long-term debt		625,928		—		—			625,928
Equity		1,631,037		978,756		(978,756	)		1,631,037

Total liabilities and equity	$	4,933,622	$	5,675,321	$	(7,328,410	)	$	3,280,533

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

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

Condensed Consolidating Statement of Operations
For the Three Months Ended March 31, 2010


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries			Total

Total operating revenues	$	—		$	212,000		$	—		$	212,000
Total operating costs and expenses		15,943			(109,325	)		—			(93,382	)

Income from operations		15,943			102,675			—			118,618
Interest expense		(11,065	)		—			—			(11,065	)
Other, net		102,602			(73	)		(102,602	)		(73	)

Income before income taxes		107,480			102,602			(102,602	)		107,480
Income tax expense		(39,940	)		—			—			(39,940	)

Net income	$	67,540		$	102,602		$	(102,602	)	$	67,540

Condensed Consolidating Statement of Operations
For the Three Months Ended March 31, 2009


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries		Total

Total operating revenues	$	—		$	86,002		$	—	$	86,002
Total operating costs and expenses		(5,217	)		(97,418	)		—		(102,635	)

Loss from operations		(5,217	)		(11,416	)		—		(16,633	)
Interest expense		(4,370	)		—			—		(4,370	)
Other, net		(11,744	)		(328	)		11,744		(328	)

Loss before income taxes		(21,331	)		(11,744	)		11,744		(21,331	)
Income tax benefit		8,106			—			—		8,106

Net loss	$	(13,225	)	$	(11,744	)	$	11,744	$	(13,225	)

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

Condensed Consolidating Statement of Cash Flows
For the Three Months Ended March 31, 2010


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries		Total

Net cash flows provided by operating activities	$	4,894		$	132,333		$	—	$	137,227
Net cash flows used in investing activities		(10,168	)		(125,128	)		—		(135,296	)
Net cash flows provided by (used in) financing activities		5,238			(3,415	)		—		1,823


Net increase (decrease) in cash and cash equivalents		(36	)		3,790			—		3,754
Cash and cash equivalents at beginning of period		48			3,186			—		3,234

Cash and cash equivalents at end of period	$	12		$	6,976		$	—	$	6,988

Condensed Consolidating Statement of Cash Flows
For the Three Months Ended March 31, 2009


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries		Total

Net cash flows provided by (used in) operating activities	$	(80,613	)	$	121,225		$	—	$	40,612
Net cash flows provided by (used in) investing activities		37,124			(131,637	)		—		(94,513	)
Net cash flows provided by (used in) financing activities		43,559			(5,003	)		—		38,556


Net increase (decrease) in cash and cash equivalents		70			(15,415	)		—		(15,345	)
Cash and cash equivalents at beginning of period		—			17,752			—		17,752

Cash and cash equivalents at end of period	$	70		$	2,337		$	—	$	2,407

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2010
Unaudited

Note Q. Supplementary information

Capitalized costs


	March 31,			December 31,
(in thousands)	2010			2009

*Oil and natural gas properties:*
Proved	$	3,271,195		$	3,139,424
Unproved		237,127			218,580
Less: accumulated depletion		(572,562	)		(517,421	)

Net capitalized costs for oil and natural gas properties	$	2,935,760		$	2,840,583

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


	Three Months Ended March 31,
(in thousands)	2010		2009

Property acquisition costs: ^(b)
Proved	$	9,842	$	(940	)
Unproved		5,356		1,221
Exploration		25,499		23,809
Development		111,706		83,779

Total costs incurred for oil and natural gas properties	$	152,403	$	107,869


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


	Three Months Ended March 31,
(in thousands)	2010			2009

Proved property acquisition costs	$	—		$	—
Exploration costs		68			168
Development costs		(2,200	)		1,151

Total	$	(2,132	)	$	1,319




(b)		During the three months ended March 31, 2009, the Company adjusted the purchase price allocation related to the acquisition of the Henry Entities. This adjustment reduced the proved acquisition costs by $940,000 and increased the unproved acquisition costs by $591,000.

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 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.

Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. 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 in 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 3.2 MMBoe of production for the first quarter of 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 overall global demand for oil; and

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

	§		the impact of the decline of 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 March 31, 2010.

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 months ended March 31, 2010 and 2009, as well as the high and low NYMEX prices for the same periods:


	Three Months Ended March 31,
	2010		2009

Average NYMEX prices:
Oil (Bbl)	$	78.61	$	43.30
Natural gas (MMBtu)	$	5.03	$	4.49

High / Low NYMEX prices:
*Oil (Bbl):*
High	$	83.76	$	54.34
Low	$	71.19	$	33.98

*Natural gas (MMBtu):*
High	$	6.01	$	6.07
Low	$	3.84	$	3.63

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $86.84 and $79.97 per Bbl and $4.28 and $3.91 per MMBtu, respectively, during the period from April 1, 2010 to May 5, 2010. At May 5, 2010, the NYMEX oil price and NYMEX natural gas price were $79.97 per Bbl and $3.99 per MMBtu, respectively.

Recent Events

Credit facility borrowing base. In April 2010, we increased our borrowing base under our credit facility to $1.2 billion, an increase of $244.1 million. Assuming this increased borrowing base was in effect at March 31, 2010, we would have had $870 million of availability under our credit facility. Our increased borrowing base provides us with more flexibility to quickly take advantage of potential acquisition opportunities should they arise.

Equity issuance. On February 1, 2010, we issued 5,347,500 shares of our common stock at $42.75 per share. After deducting underwriting discounts of approximately $9.1 million and transaction costs, we received net proceeds of approximately $219.5 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 we closed two acquisitions of interests in producing and non-producing assets in the Wolfberry play of the Permian Basin, together with the acquisition of related additional interests that closed in 2010, for approximately $270.7 million in cash, subject to usual and customary post-closing adjustments (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. We expect to be able to fund our 2010 capital budget substantially within our cash flow. 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 remain substantially within our cash flow. The following is a summary of our 2010 capital budget:


	2010
(in millions)	Budget

Drilling and recompletion opportunities in our core operating area	$	502
Projects operated by third parties		8
Emerging plays, acquisition of leasehold acreage and other property interests, and geological and geophysical		82
Facilities capital in our core operating areas		33

Total 2010 capital budget	$	625

Derivative Financial Instruments

Derivative financial instrument exposure. At March 31, 2010, the fair value of our financial derivatives was a net liability of $40.4 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. Pursuant to 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 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 first quarter of 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 three months ended March 31, 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		792,000	$	81.77	^(a)		1/1/11 - 12/31/11
Price swap		168,000	$	89.00	^(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.

Second quarter 2010 commodity derivative contracts. After March 31, 2010 and through May 5, 2010, we entered into the following oil price commodity derivative contracts to hedge an additional portion of our estimated future production:

Aggregate

Index

Contract

Volume

Price

Period

Oil (volumes in Bbls):

Price swap

1,463,000

88.63

^(a)

5/1/10 - 12/31/10

Price swap

1,344,000

92.25

^(a)

1/1/11 - 12/31/11

Price swap

2,040,000

92.98

^(a)

1/1/12 - 12/31/12


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

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 months ended March 31, 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 March 31,
	2010		2009

Production and operating data:
Net production volumes:
Oil (MBbl)		2,170		1,687
Natural gas (MMcf)		6,241		4,955
Total (MBoe)		3,210		2,513

Average daily production volumes:
Oil (Bbl)		24,111		18,744
Natural gas (Mcf)		69,344		55,056
Total (Boe)		35,668		27,922

Average prices:
Oil, without derivatives (Bbl)	$	74.99	$	38.51
Oil, with derivatives (Bbl) ^(a)	$	70.32	$	59.01
Natural gas, without derivatives (Mcf)	$	7.90	$	4.24
Natural gas, with derivatives (Mcf) ^(a)	$	7.98	$	4.76
Total, without derivatives (Boe)	$	66.04	$	34.22
Total, with derivatives (Boe) ^(a)	$	63.04	$	49.00

Operating costs and expenses per Boe:
Lease operating expenses and workover costs	$	5.84	$	6.76
Oil and natural gas taxes	$	5.59	$	3.10
General and administrative	$	4.22	$	4.68
Depreciation, depletion and amortization	$	16.77	$	20.20


(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 March 31,
(in thousands)	2010			2009

Gain (loss) on derivatives not designated as hedges:
Cash (payments on) receipts from oil derivatives	$	(10,133	)	$	34,584
Cash receipts from natural gas derivatives		506			2,540
Cash payments on interest rate derivatives		(1,213	)		—
Unrealized mark-to-market gain (loss) on commodity and interest rate derivatives		26,413			(42,170	)

Gain (loss) on derivatives not designated as hedges	$	15,573		$	(5,046	)

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


	Three Months Ended March 31,
	2010				2009
	West		Grayburg		Grayburg
	Wolfberry		Jackson		Jackson

Production and operating data:
Net production volumes:
Oil (MBbl)		330		409		324
Natural gas (MMcf)		985		1,147		942
Total (MBoe)		494		600		481

Average prices:
Oil, without derivatives (Bbl)	$	76.76	$	75.38	$	36.88
Natural gas, without derivatives (Mcf)	$	8.37	$	8.10	$	4.56
Total, without derivatives (Boe)	$	67.94	$	66.86	$	33.77

Production costs per Boe:
Lease operating expenses including workovers	$	4.67	$	5.65	$	6.35
Oil and natural gas taxes	$	4.53	$	5.74	$	2.96

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009

Oil and natural gas revenues. Revenue from oil and natural gas operations was $212.0 million for the three months ended March 31, 2010, an increase of $126.0 million (147 percent) from $86.0 million for the three months ended March 31, 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 $74.99 per Bbl during the three months ended March 31, 2010, an increase of 95 percent from $38.51 per Bbl during the three months ended March 31, 2009;

	•		total oil production was 2,170 MBbl for the three months ended March 31, 2010, an increase of 483 MBbl (29 percent) from 1,687 MBbl for the three months ended March 31, 2009;

	•		average realized natural gas price (excluding the effects of derivative activities) was $7.90 per Mcf during the three months ended March 31, 2010, an increase of 86 percent from $4.24 per Mcf during the three months ended March 31, 2009; and

	•		total natural gas production was 6,241 MMcf for the three months ended March 31, 2010, an increase of 1,286 MMcf (26 percent) from 4,955 MMcf for the three months ended March 31, 2009.

Production expenses. The following table provides the components of our total oil and natural gas production costs for the three months ended March 31, 2010 and 2009:


	Three Months Ended March 31,
	2010				2009
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe

Lease operating expenses	$	18,376	$	5.72	$	16,568	$	6.59
Taxes:
Ad valorem		2,955		0.92		1,502		0.60
Production		14,998		4.67		6,275		2.50
Workover costs		371		0.12		421		0.17

Total oil and natural gas production expenses	$	36,700	$	11.43	$	24,766	$	9.86

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 $18.4 million ($5.72 per Boe) for the three months ended March 31, 2010, an increase of $1.8 million (11 percent) from $16.6 million ($6.59 per Boe) for the three months ended March 31, 2009. The increase in lease operating expenses is 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 is primarily due to (i) additional production from our wells successfully drilled and completed in 2009 and 2010 where we are receiving benefits from economies of scale and (ii) a general inflation of field service and supply costs during the first quarter of 2009 associated with high commodity prices during late 2008.

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 drilling activity.

Production taxes per unit of production were $4.67 per Boe during the three months ended March 31, 2010, an increase of 87 percent from $2.50 per Boe during the three months ended March 31, 2009. The increase is 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 Boe prices (before the effects of hedging) increased 93 percent.

Workover expenses were approximately $0.4 million for the three months ended March 31, 2010 and 2009. The 2010 and 2009 amounts related primarily to workovers in the New Mexico Permian area and the Texas Permian area, respectively.

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the three months ended March 31, 2010 and 2009:


	Three Months Ended March 31,
(in thousands)	2010		2009

Geological and geophysical	$	668	$	677
Exploratory dry holes		218		1,421
Leasehold abandonments and other		409		3,897

Total exploration and abandonments	$	1,295	$	5,995

Our geological and geophysical expense, which primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, was $0.7 million both for the three months ended March 31, 2010 and 2009.

During the three months ended March 31, 2009, we wrote-off an unsuccessful exploratory well in our Arkansas emerging play.

For the three months ended March 31, 2010, we recorded $0.4 million of leasehold abandonments, which were primarily related to prospects in our Texas Permian area. For the three months ended March 31, 2009, we recorded approximately $3.9 million of leasehold abandonments, which relates primarily to the write-off of prospects in our New Mexico Permian and Texas Permian areas.

Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the three months ended March 31, 2010 and 2009:


	Three Months Ended March 31,
	2010				2009
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe

Depletion of proved oil and natural gas properties	$	52,767	$	16.44	$	49,777	$	19.81
Depreciation of other property and equipment		689		0.21		578		0.23
Amortization of intangible asset — operating rights		387		0.12		393		0.16

Total depletion, depreciation and amortization	$	53,843	$	16.77	$	50,748	$	20.20


Oil price used to estimate proved oil reserves at period end	$	66.13			$	44.63
Natural gas price used to estimate proved natural gas reserves at period end	$	3.99			$	3.63

Depletion of proved oil and natural gas properties was $52.8 million ($16.44 per Boe) for the three months ended March 31, 2010, an increase of $3.0 million from $49.8 million ($19.81 per Boe) for the three months ended March 31, 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, offset 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 and (ii) 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 quarter of 2010. Our first quarter of 2010 depletion expense rate was $16.44 per Boe, which is lower than past quarters in part due to the 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 $2.4 million during the three months ended March 31, 2010, which was primarily attributable to natural gas related properties in our New Mexico and Texas Permian areas. For the three months ended March 31, 2009, we recognized a non-cash charge against earnings of $4.1 million, which was primarily attributable to 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 three months ended March 31, 2010 and 2009:


	Three Months Ended March 31,
	2010						2009
				Per						Per
(in thousands, except per unit amounts)	Amount			Boe			Amount			Boe

General and administrative expenses — recurring	$	11,121		$	3.45		$	9,914		$	3.95
Non-recurring bonus paid to Henry Entities’ employees, see Note K		2,468			0.77			2,561			1.02
Non-cash stock-based compensation — stock options		1,009			0.31			1,028			0.41
Non-cash stock-based compensation — restricted stock		1,822			0.57			897			0.36
Less: Third-party operating fee reimbursements		(2,862	)		(0.88	)		(2,654	)		(1.06	)

Total general and administrative expenses	$	13,558		$	4.22		$	11,746		$	4.68

General and administrative expenses were $13.6 million ($4.22 per Boe) for the three months ended March 31, 2010, an increase of $1.9 million (16 percent) from $11.7 million ($4.68 per Boe) for the three months ended March 31, 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, partially offset by an increase in third-party operating fee reimbursements. The decrease in 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 $2.9 million and $2.7 million during the three months ended March 31, 2010 and 2009, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations.

(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 March 31, 2010 and 2009:


	Three Months Ended March 31,
(in thousands)	2010			2009

*Cash payments (receipts):*
Commodity derivatives — oil	$	10,133		$	(34,584	)
Commodity derivatives — natural gas		(506	)		(2,540	)
Financial derivatives — interest		1,213			—
*Mark-to-market (gain) loss:*
Commodity derivatives — oil		(1,438	)		39,037
Commodity derivatives — natural gas		(27,187	)		706
Financial derivatives — interest		2,212			2,427

(Gain) loss on derivatives not designated as hedges	$	(15,573	)	$	5,046

Interest expense. The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the three months ended March 31, 2010 and 2009:


	Three Months Ended March 31,
(dollars in thousands)	2010			2009

Interest expense	$	11,065		$	4,370
Weighted average interest rate		5.2	%		2.0	%
Weighted average debt balance	$	711.0		$	655.9

The increase in interest expense of approximately $6.7 million is due to interest costs on our 8.625% unsecured senior notes that were issued in September 2009. The increase in the weighted average debt balance during the three months ended March 31, 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 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 $39.9 million and an income tax benefit of $8.1 million for the three months ended March 31, 2010 and 2009, respectively. The effective income tax rate for the three months ended March 31, 2010 and 2009 was 37.2 percent and 38.0 percent, respectively.

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 three months ended March 31, 2010 and 2009 totaled $139.3 million and $106.3 million, respectively, as compared to the comparable amount in cash flows used by investing activities of $113.7 million and $131.6 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. We expect to be able to fund our 2010 capital budget substantially within our cash flow. 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 remain substantially within our cash flow.

Other than the purchase of leasehold acreage and other miscellaneous property interests, our 2010 capital budget is exclusive of acquisitions. 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 believe that our available cash and cash flows will substantially fund our 2010 non-acquisition capital expenditures, 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 2010 capital budget.

Acquisitions. Our expenditures for acquisitions of proved and unproved properties during the three months ended March 31, 2010 and 2009 totaled $15.2 million and $0.3 million, respectively. The proved acquisitions during the three months ended March 31, 2010, primarily relate to additional interests that we closed in 2010 on the Wolfberry Acquisitions.

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 $220.0 million decrease in outstanding long-term borrowings, a $27.9 million decrease in cash interest expense on debt and a $26.4 million decrease in our net commodity derivative obligations. 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 three months ended March 31, 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 should be sufficient to meet both our short-term working capital requirements and our 2010 capital expenditure plans. If our cash flows are not sufficient, 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 $137.2 million and $40.6 million for the three months ended March 31, 2010 and 2009, respectively. The increase in operating cash flows during the three months ended March 31, 2010 over 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 three months ended March 31, 2010 and 2009, we invested $113.7 million and $131.6 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 three months ended March 31, 2010 over 2009, due to an increase in our cash settlements paid on derivatives not designated as hedges, offset by a reduction in capital expenditures on oil and natural gas properties.

Cash flow from financing activities. Net cash provided by financing activities was $1.8 million and $38.6 million for the three months ended March 31, 2010 and 2009, respectively. During the three months ended March 31, 2010, we reduced our outstanding balance on our credit facility by $220.0 million primarily using proceeds from the issuance of common stock. During the three months ended March 31, 2009, we had net borrowings of $40.8 million under our credit facility.

Our credit facility, as amended, has a maturity date of July 31, 2013. At March 31, 2010, we had letters of credit outstanding under the credit facility of approximately $25,000, and our availability to borrow additional funds was approximately $625.9 million

based on the borrowing base at the time of $955.9 million. In April 2010, the lenders increased our borrowing base to $1.2 billion, an increase of over $244 million, under the credit facility until the next scheduled borrowing base redetermination 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.

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 March 31, 2010) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). At March 31, 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 March 31, 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 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 5.3 million shares of our common stock at $42.75 per share. After deducting underwriting discounts of approximately $9.1 million and transaction costs, we received net proceeds of approximately $219.5 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 March 31, 2010, after giving effect to our April 2010 increased borrowing base under our credit facility of $1.2 billion, we would have had $870.0 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 until 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 March 31, 2010, we had $7.0 million of cash on hand.

At March 31, 2010, after giving effect to our April 2010 increased borrowing base under our credit facility of $1.2 billion, we would have had $870.0 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 commodity prices and the state of the financial markets, there is no assurance that our borrowing base will not be reduced.

Book capitalization and current ratio. Our book capitalization at March 31, 2010 was $2,257.0 million, consisting of debt of $625.9 million and stockholders’ equity of $1,631.0 million. Our debt to book capitalization was 28 percent and 39 percent at March 31, 2010 and December 31, 2009, respectively. Our ratio of current assets to current liabilities was 0.62 to 1.00 at March 31, 2010 as compared to 0.64 to 1.00 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 three months ended March 31, 2010, we received an average of $74.99 per barrel of oil and $7.90 per Mcf of natural gas before consideration of commodity derivative contracts compared to $38.51 per barrel of oil and $4.24 per Mcf of natural gas in the three months ended March 31, 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 three months ended March 31, 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

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, 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.

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 March 31, 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 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 fixed 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 March 31, 2010, would have increased the net unrealized loss on our commodity price risk management contracts by approximately $93.2 million.

At March 31, 2010, we had (i) oil price swaps that settle on a monthly basis covering future oil production from April 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 April 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 the commodity derivative contracts. The average NYMEX oil futures price and average NYMEX natural gas futures price for the three months ended March 31, 2010, was $78.61 per Bbl and $5.03 per MMBtu, respectively. At May 5, 2010, the NYMEX oil futures price and NYMEX natural gas futures price were $79.97 per Bbl and $3.99 per MMBtu, respectively. A decrease in oil and natural gas prices would decrease the fair value liability of our commodity derivative contracts from their recorded balance at March 31, 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 decrease in our fair value liability would be recorded in earnings as an unrealized gain. However, an increase in the average NYMEX oil and natural gas futures price above those at March 31, 2010, would result in an increase in our fair value liability 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 March 31, 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

in future interest rates of 25 basis points from the future rate at March 31, 2010, would have decreased our net unrealized value on our interest rate risk management contracts by approximately $1.6 million.

We had total indebtedness of $330.0 million outstanding under our credit facility at March 31, 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 $3.3 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 three months ended March 31, 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)		18,998			(3,425	)		15,573
Contract maturities		9,627			1,213			10,840

Fair value of contracts outstanding at March 31, 2010	$	(35,707	)	$	(4,713	)	$	(40,420	)


(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 March 31, 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.

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 also party to other 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. 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.

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

January 1, 2010 - January 31, 2010

—

February 1, 2010 - February 28, 2010

4,678

46.75

—

March 1, 2010 - March 31, 2010

—


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

Item 6. Exhibits


Exhibit
Number		Exhibit
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 4.1 to the Company’s Current Report on Form 8-K on April 29, 2010, and incorporated herein by reference).

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.


(a)		Filed herewith.

(b)		Furnished herewith.

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: May 7, 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)

EXHIBIT INDEX


Exhibit
Number		Exhibit
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 4.1 to the Company’s Current Report on Form 8-K on April 29, 2010, and incorporated herein by reference).

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.


(a)		Filed herewith.

(b)		Furnished herewith.