Edgar Filing: CONCHO RESOURCES INC

Large accelerated filer

Accelerated filer ¨

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

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, 2012

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

For the transition period from to

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)


Delaware		76-0818600

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

550 West Texas Avenue, Suite 100 Midland, Texas		79701

(Address of principal executive offices)		(Zip code)

(432) 683-7443

(Registrant’s telephone number, including area code)

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

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 þ No ¨

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.

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

Number of shares of the registrant’s common stock outstanding at May 1, 2012: 104,021,503 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			52
Item 4. Controls and Procedures			53

PART II – OTHER INFORMATION			54

Item 1. Legal Proceedings			54
Item 1A. Risk Factors			54
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			54
Item 6. Exhibits			55

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by the forward-looking statements. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made. We disclaim any obligation to update or revise these statements unless required by securities law, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2011 and in this report, 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;

•

drilling and operating risks, including risks related to properties where we do not serve as the operator and risks related to hydraulic fracturing activities;

•

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

•

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

•

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

•

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

•

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

•

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

•

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; and

•

uncertainty concerning our assumed or possible future results of operations.

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, 2012 and December 31, 2011			1

Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011			2

Consolidated Statement of Stockholders' Equity for the Three Months Ended March 31, 2012			3

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011			4

Condensed Notes to Consolidated Financial Statements			5

iii

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited


(in thousands, except share and per share amounts)	March 31, 2012		December 31, 2011
Assets

Current assets:
Cash and cash equivalents	$	606	$	342
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas		222,253		213,921
Joint operations and other		192,552		153,746
Derivative instruments		-		1,698
Deferred income taxes		47,579		28,793
Prepaid costs and other		11,501		12,523

Total current assets		474,491		411,023

Property and equipment:
Oil and natural gas properties, successful efforts method		7,919,692		7,347,460
Accumulated depletion and depreciation		(1,249,959)		(1,116,545)

Total oil and natural gas properties, net		6,669,733		6,230,915
Other property and equipment, net		77,036		59,203

Total property and equipment, net		6,746,769		6,290,118

Funds held in escrow		-		17,394
Deferred loan costs, net		72,985		65,641
Intangible asset—operating rights, net		33,038		33,425
Inventory		12,184		19,419
Noncurrent derivative instruments		14		7,944
Other assets		7,128		4,612

Total assets	$	7,346,609	$	6,849,576

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	11,480	$	23,341
Related parties		145		11
Bank overdrafts		70,158		39,241
Revenue payable		177,783		146,061
Accrued and prepaid drilling costs		360,224		293,919
Derivative instruments		116,959		56,218
Other current liabilities		131,062		142,686

Total current liabilities		867,811		701,477

Long-term debt		2,281,752		2,080,141
Deferred income taxes		1,026,869		1,002,295
Noncurrent derivative instruments		88,066		32,254
Asset retirement obligations and other long-term liabilities		56,388		52,670
Commitments and contingencies (Note J)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 104,093,681 and 103,756,222 shares issued at March 31, 2012 and December 31, 2011, respectively		104		104
Additional paid-in capital		1,941,662		1,925,757
Retained earnings		1,089,991		1,058,874
Treasury stock, at cost; 74,273 and 55,990 shares at March 31, 2012 and December 31, 2011,respectively		(6,034)		(3,996)

Total stockholders’ equity		3,025,723		2,980,739

Total liabilities and stockholders’ equity	$	7,346,609	$	6,849,576

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)	2012		2011
Operating revenues:
Oil sales	$	413,647	$	282,427
Natural gas sales		94,158		78,413

Total operating revenues		507,805		360,840

Operating costs and expenses:
Oil and natural gas production		92,150		63,658
Exploration and abandonments		5,979		726
Depreciation, depletion and amortization		135,869		90,288
Accretion of discount on asset retirement obligations		988		704
General and administrative (including non-cash stock-based compensation of $6,128 and $4,468 for the three months ended March 31, 2012 and 2011, respectively)		27,387		21,392
Loss on derivatives not designated as hedges		158,093		233,142

Total operating costs and expenses		420,466		409,910

Income (loss) from operations		87,339		(49,070)

Other income (expense):
Interest expense		(35,837)		(29,660)
Other, net		(1,268)		(352)

Total other expense		(37,105)		(30,012)

Income (loss) from continuing operations before income taxes		50,234		(79,082)
Income tax benefit (expense)		(19,117)		30,469

Income (loss) from continuing operations		31,117		(48,613)
Income from discontinued operations, net of tax		-		91,188

Net income	$	31,117	$	42,575

Basic earnings per share:
Income (loss) from continuing operations	$	0.30	$	(0.48)
Income from discontinued operations, net of tax		-		0.90

Net income	$	0.30	$	0.42

Weighted average shares used in basic earnings per share		102,854		102,242

Diluted earnings per share:
Income (loss) from continuing operations	$	0.30	$	(0.48)
Income from discontinued operations, net of tax		-		0.90

Net income	$	0.30	$	0.42

Weighted average shares used in diluted earnings per share		103,770		102,242

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, 2011		103,756	$	104	$	1,925,757	$	1,058,874		56	$	(3,996)	$	2,980,739
Net income		-		-		-		31,117		-		-		31,117
Stock options exercised		181		-		2,996		-		-		-		2,996
Grants of restricted stock		166		-		-		-		-		-		-
Cancellation of restricted stock		(9)		-		-		-		-		-		-
Stock-based compensation		-		-		6,128		-		-		-		6,128
Excess tax benefits related to stock-based compensation		-		-		6,781		-		-		-		6,781
Purchase of treasury stock		-		-		-		-		18		(2,038)		(2,038)

BALANCE AT MARCH 31, 2012		104,094	$	104	$	1,941,662	$	1,089,991		74	$	(6,034)	$	3,025,723

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)	2012		2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	31,117	$	42,575
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		135,869		90,288
Accretion of discount on asset retirement obligations		988		704
Exploration and abandonments, including dry holes		3,102		138
Non-cash compensation expense		6,128		4,468
Deferred income taxes		12,569		(37,576)
Loss on sale of assets, net		895		24
Loss on derivatives not designated as hedges		158,093		233,142
Discontinued operations		-		(82,118)
Other non-cash items		2,818		3,435
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		(19,102)		(64,737)
Prepaid costs and other		(1,494)		501
Inventory		6,328		(11,558)
Accounts payable		(11,727)		(35,101)
Revenue payable		31,722		24,596
Other current liabilities		(11,401)		(3,296)

Net cash provided by operating activities		345,905		165,485

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and natural gas properties		(541,665)		(354,194)
Additions to other property and equipment		(20,234)		(18,333)
Proceeds from the sale of assets		669		196,213
Funds held in escrow		17,394		-
Settlements paid on derivatives not designated as hedges		(31,911)		(28,296)

Net cash used in investing activities		(575,747)		(204,610)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt		1,180,000		516,000
Payments of debt		(978,500)		(529,000)
Exercise of stock options		2,996		5,189
Excess tax benefit from stock-based compensation		6,781		17,043
Payments for loan costs		(10,050)		-
Purchase of treasury stock		(2,038)		(1,338)
Bank overdrafts		30,917		31,755

Net cash provided by financing activities		230,106		39,649

Net increase in cash and cash equivalents		264		524
Cash and cash equivalents at beginning of period		342		384

Cash and cash equivalents at end of period	$	606	$	908

SUPPLEMENTAL CASH FLOWS:
Cash paid for interest and fees, net of $73 capitalized interest in 2011	$	51,647	$	10,322
Cash paid for income taxes	$	5,455	$	5,608

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

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

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 primarily located 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. In addition, a third-party had previously formed an entity to effectuate a tax-free exchange of assets for the Company. The Company had 100 percent control over the decisions of the entity, but had no direct ownership. The third-party conveyed ownership to the Company upon completion of the tax-free exchange process in April 2011, and the entity was subsequently merged into a wholly-owned subsidiary of the Company. It has been consolidated in the Company’s financial statements since its formation. All material intercompany balances and transactions have been eliminated.

Discontinued operations. In March 2011, the Company sold its Bakken assets for cash consideration of approximately $195.9 million. In 2011, after completion of the final post-closing adjustments, the Company recognized a pre-tax gain on the sale of assets of approximately $135.9 million; however, through the three months ended March 31, 2011, the Company’s results of operations reflected a pre-tax gain on sale of assets of approximately $142.0 million. The Company has reflected the results of operations of these divested assets as discontinued operations, rather than as a component of continuing operations. See Note M for additional information regarding these divestitures and their discontinued operations.

Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, the asset retirement obligations, fair value of derivative financial instruments, fair value measurements for business combinations 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, 2011 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, 2012, and its results of operations and cash flows for the three months ended March 31, 2012 and 2011. 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 included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

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 $73.0 million and $65.6 million, net of accumulated amortization of $29.5 million and $26.8 million, at March 31, 2012 and December 31, 2011, respectively.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Future amortization expense of deferred loan costs at March 31, 2012 was as follows:



(in thousands)

Remaining 2012	$	8,623
2013		11,734
2014		12,024
2015		12,338
2016		7,369
Thereafter		20,897

Total	$	72,985

Intangible assets. The Company has capitalized certain operating rights acquired in an acquisition. The gross operating rights, which have no residual value, are amortized over the estimated economic life of 25 years. Impairment will be assessed if indicators of potential impairment exist or when there is a material change in the remaining useful economic life. The following table reflects the gross and net intangible assets at March 31, 2012 and December 31, 2011:


(in thousands)	March 31, 2012		December 31, 2011

Gross intangible - operating rights	$	38,717	$	38,717
Accumulated amortization		(5,679)		(5,292)

Net intangible - operating rights	$	33,038	$	33,425

The following table reflects amortization expense for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
(in thousands)	2012		2011

Amortization expense	$	387	$	387

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

The following table reflects the estimated aggregate amortization expense for each of the periods presented below at March 31, 2012:


(in thousands)

Remaining 2012	$	1,162
2013		1,549
2014		1,549
2015		1,549
2016		1,549
Thereafter		25,680

Total	$	33,038

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.

Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.

General and administrative expense. The Company receives fees for the operation of jointly owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $3.8 million and $2.6 million for the three months ended March 31, 2012 and 2011, respectively.

Recent accounting pronouncements. In December 2011, the Financial Accounting Standards Board (the “FASB”) issued amendments to enhance disclosures required by U.S. GAAP by requiring improved information about financial instruments and derivative instruments that are either (i) offset in accordance with the current definition of “right of setoff” or the current balance sheet netting for derivative instruments allowed under current U.S. GAAP or (ii) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either the definition of “right of setoff” or the current balance sheet netting for derivative instruments. This information will enable users of an entity’s financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments in the scope of the update.

An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The Company plans to adopt on January 1, 2013 and does not expect this update to have a significant impact on the consolidated financial statements.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

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, 2012:


(in thousands)	Three Months Ended March 31, 2012
Beginning capitalized exploratory well costs	$	107,767
Additions to exploratory well costs pending the determination of proved reserves		101,745
Reclassifications due to determination of proved reserves		(113,454)
Exploratory well costs charged to expense		-

Ending capitalized exploratory well costs	$	96,058

The following table provides an aging at March 31, 2012 and December 31, 2011 of capitalized exploratory well costs based on the date drilling was completed:


(in thousands)	March 31, 2012		December 31, 2011
Exploratory wells in progress	$	25,610	$	24,963
Capitalized exploratory well costs that have been capitalized for a period of one year or less		70,448		82,804
Capitalized exploratory well costs that have been capitalized for a period greater than one year		-		-

Total capitalized exploratory well costs	$	96,058	$	107,767

At March 31, 2012, the Company had 70 gross exploratory wells either drilling or waiting on results from completion, of which 24 wells were in the New Mexico Shelf area, 25 wells were in the Delaware Basin area and 21 wells were in the Texas Permian area.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Note D. Acquisitions and business combinations

PDC Acquisition. In February 2012, the Company acquired certain producing and non-producing assets from Petroleum Development Corporation (the “PDC Acquisition”) for cash consideration of approximately $184.4 million, subject to customary post-closing adjustments. The PDC Acquisition was primarily funded with borrowings under the Company’s credit facility. The results of operations prior to March 2012 do not include results from the PDC Acquisition.

The amounts reflected in the Company’s financial statements reflect management’s initial estimates of the fair values of the acquired assets and liabilities. Adjustments to the estimated asset values will be made once the final valuations are complete. The initial acquisition accounting as of March 31, 2012 is as follows:



(in thousands)
Fair value of net assets:
Proved oil and natural gas properties	$	156,812
Unproved oil and natural gas properties		29,687

Total assets acquired		186,499

Asset retirement obligations assumed		(2,050)

Fair value of net assets acquired	$	184,449

Fair value of consideration paid for net assets:
Cash consideration	$	184,449

OGX Acquisition. In November 2011, the Company acquired three entities affiliated with OGX Holdings II, LLC (collectively the “OGX Acquisition”) for cash consideration of approximately $252.0 million. The OGX Acquisition was primarily funded with borrowings under the Company’s credit facility. The results of operations prior to December 2011 do not include results from the OGX Acquisition.

The following table reflects the estimated fair value of the acquired assets and liabilities associated with the OGX Acquisition:



(in thousands)
Fair value of net assets:
Current assets, net of cash acquired of $205	$	5,579
Proved oil and natural gas properties		98,383
Unproved oil and natural gas properties		164,798

Total assets acquired		268,760

Current liabilities		(16,438)
Asset retirement obligations		(321)

Total liabilities assumed		(16,759)

Fair value of net assets acquired	$	252,001

Fair value of consideration paid for net assets:
Cash consideration, net of cash acquired of $205	$	252,001

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

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 Company’s asset retirement obligation transactions during the three months ended March 31, 2012 and 2011 are summarized in the table below:


	Three Months Ended March 31,
(in thousands)	2012		2011

Asset retirement obligations, beginning of period	$	59,685	$	43,326
Liabilities incurred from new wells		1,777		1,823
Liabilities assumed in acquisitions		2,050		148
Accretion expense for continuing operations		988		704
Accretion expense for discontinued operations		-		8
Disposition of wells		-		(412)
Liabilities settled upon plugging and abandoning wells		(110)		(301)
Revision of estimates		(935)		(1,508)

Asset retirement obligations, end of period	$	63,455	$	43,788

Note F. Incentive plans

Defined contribution plan. The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees. Currently, the Company matches 100 percent of employee contributions, not to exceed 10 percent of the employee’s annual salary. The Company’s contributions to the plans for the three months ended March 31, 2012 and 2011, were approximately $0.9 million and $0.4 million, respectively.

Stock incentive plan. The Company’s 2006 Stock Incentive Plan (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, 2012:


	Number of Common Shares

Approved and authorized awards		5,850,000
Stock option grants, net of forfeitures		(3,463,720)
Restricted stock grants, net of forfeitures		(1,727,245)
Treasury shares		74,273

Awards available for future grant		733,308

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Restricted stock awards. All restricted shares are treated as issued and outstanding in the accompanying consolidated balance sheets. If an employee terminates employment prior to 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 for the three months ended March 31, 2012 is presented below:


	Number of Restricted Shares		Grant Date Fair Value Per Share

*Restricted stock:*
Outstanding at December 31, 2011		912,013
Shares granted		165,840	$	112.85
Shares cancelled / forfeited		(8,851)
Lapse of restrictions		(81,601)

Outstanding at March 31, 2012		987,401

The following table summarizes information about stock-based compensation for the Company’s restricted stock awards activity under the Plan for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
(in thousands)	2012		2011

*Grant date fair value for awards during the period:*
Employee grants	$	1,254	$	1,930
Officer and director grants		17,461		8,800

Total	$	18,715	$	10,730

*Stock-based compensation expense from restricted stock:*
Employee grants	$	2,742	$	1,842
Officer and director grants		3,277		2,286

Total	$	6,019	$	4,128

*Income taxes and other information:*
Income tax benefit related to restricted stock	$	2,301	$	1,578
Deductions in current taxable income related to restricted stock	$	9,017	$	7,078

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Stock option awards. A summary of the Company’s stock option awards activity under the Plan for the three months ended March 31, 2012 is presented below:


	Number of Options		Weighted Average Exercise Price

*Stock options:*
Outstanding at December 31, 2011		930,178	$	18.10
Options exercised		(180,470)	$	16.60

Outstanding at March 31, 2012		749,708	$	18.46

Vested and exercisable at end of period		715,531	$	18.29

The following table summarizes information about the Company’s vested and exercisable stock options outstanding at March 31, 2012:


			Weighted
			Average		Weighted
Range of	Number		Remaining		Average
Exercise	Vested and		Contractual		Exercise		Intrinsic
Prices	Exercisable		Life		Price		Value
							(in thousands)
Vested and exercisable options:
$8.00		117,053		2.37 years	$	8.00	$	11,012
$12.00		45,911		3.59 years	$	12.00		4,136
$12.50 - $15.50		140,000		4.33 years	$	15.13		12,173
$20.00 - $23.00		356,312		6.06 years	$	21.68		28,649
$28.00 - $37.27		56,255		6.14 years	$	31.29		3,982

		715,531		4.97 years	$	18.29	$	59,952

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

The following table summarizes information about stock-based compensation for stock options for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
(in thousands)	2012		2011

*Stock-based compensation expense from stock options:*
Employee grants	$	9	$	23
Officer and director grants		100		317

Total	$	109	$	340


*Income taxes and other information:*
Income tax benefit related to stock options	$	42	$	130
Deductions in current taxable income related to stock options exercised	$	15,016	$	43,241

Future stock-based compensation expense. The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at March 31, 2012:


	Restricted		Stock
(in thousands)	Stock		Options		Total
Remaining 2012	$	20,047	$	77	$	20,124
2013		17,532		15		17,547
2014		9,063		-		9,063
2015		1,486		-		1,486
2016 and thereafter		133		-		133

Total	$	48,261	$	92	$	48,353

Note G. 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

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited



		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.

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, 2012, 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)		2012

Assets:
Commodity derivative price swap contracts	$	-	$	12,266	$	-	$	12,266

		-		12,266		-		12,266

Liabilities:
Commodity derivative price swap contracts		-		(217,277)		-		(217,277)

		-		(217,277)		-		(217,277)

Net financial liabilities	$	-	$	(205,011)	$	-	$	(205,011)

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

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, 2012 and December 31, 2011:


	March 31, 2012				December 31, 2011
	Carrying		Fair		Carrying		Fair
(in thousands)	Value		Value		Value		Value
Assets:
Derivative instruments	$	14	$	14	$	9,642	$	9,642

Liabilities:
Derivative instruments	$	205,025	$	205,025	$	88,472	$	88,472
Credit facility	$	185,000	$	173,154	$	583,500	$	532,805
8.625% senior notes due 2017	$	296,752	$	324,943	$	296,641	$	324,080
7.0% senior notes due 2021	$	600,000	$	643,500	$	600,000	$	644,400
6.5% senior notes due 2022	$	600,000	$	633,000	$	600,000	$	627,000
5.5% senior notes due 2022	$	600,000	$	591,000	$	-	$	-

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 values of the Company’s 8.625%, 7.0%, 6.5% and 5.5% senior notes are based on quoted market prices.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Derivative instruments. The fair value of the Company’s derivative instruments is 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 summarizes (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) 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, 2012 and December 31, 2011:


	Fair Value Measurements Using
(in thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value at March 31, 2012

Assets ^(a)
Current:^(b)
Commodity derivative price swap contracts	$	-	$	11,969	$	-	$	11,969

		-		11,969		-		11,969
Noncurrent:^(c)
Commodity derivative price swap contracts		-		297		-		297

		-		297		-		297
Liabilities ^(a)
Current:^(b)
Commodity derivative price swap contracts		-		(128,928)		-		(128,928)

		-		(128,928)		-		(128,928)
Noncurrent:^(c)
Commodity derivative price swap contracts		-		(88,349)		-		(88,349)

		-		(88,349)		-		(88,349)

Net financial liabilities	$	-	$	(205,011)	$	-	$	(205,011)

(b) Total current financial liabilities, gross basis							$	(116,959)
(c) Total noncurrent financial liabilities, gross basis								(88,052)

Net financial liabilities							$	(205,011)

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited


	Fair Value Measurements Using
(in thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value at December 31, 2011

Assets ^(a)
Current:^(b)
Commodity derivative price swap contracts	$	-	$	28,485	$	-	$	28,485

		-		28,485		-		28,485
Noncurrent:^(c)
Commodity derivative price swap contracts		-		19,122		-		19,122

		-		19,122		-		19,122
Liabilities ^(a)
Current:^(b)
Commodity derivative price swap contracts		-		(83,005)		-		(83,005)

		-		(83,005)		-		(83,005)
Noncurrent:^(c)
Commodity derivative price swap contracts		-		(43,432)		-		(43,432)

		-		(43,432)		-		(43,432)

Net financial assets (liabilities)	$	-	$	(78,830)	$	-	$	(78,830)


(b) Total current financial liabilities, gross basis							$	(54,520)
(c) Total noncurrent financial liabilities, gross basis								(24,310)

Net financial liabilities							$	(78,830)

(a)

The fair value of derivative instruments reported in the Company’s consolidated balance sheets is subject to netting arrangements and qualifies for net presentation. The following table reports the net basis derivative fair values as reported in the consolidated balance sheets at March 31, 2012 and December 31, 2011:


(in thousands)	March 31, 2012		December 31, 2011

Consolidated Balance Sheet Classification:

Current derivative contracts:
Assets	$	-	$	1,698
Liabilities		(116,959)		(56,218)

Net current	$	(116,959)	$	(54,520)

Noncurrent derivative contracts:
Assets	$	14	$	7,944
Liabilities		(88,066)		(32,254)

Net noncurrent	$	(88,052)	$	(24,310)

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

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 this 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 price fluctuations for impairment. Impairment expense is caused primarily due to declines in commodity prices and well performance. The Company did not recognize any impairment charges for the three months ended March 31, 2012 or 2011.

Asset retirement obligations – The Company estimates the fair value of Asset Retirement Obligations (“AROs”) based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; 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 AROs.

The following table sets forth the measurement information for assets measured at fair value on a nonrecurring basis:


	Fair Value Measurements Using
(in thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)

Three Months Ended March 31, 2012:
Asset retirement obligations incurred in current period		-		-		1,777

Three Months Ended March 31, 2011:
Asset retirement obligations incurred in current period		-		-		1,823

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Note H. Derivative financial instruments

The Company uses derivative financial contracts to manage its exposure 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. The Company does not enter into derivative financial instruments for speculative or trading purposes. 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 as they occur.

New commodity derivative contracts in the first three months of 2012. During the three months ended March 31, 2012, the Company entered into additional commodity derivative contracts to hedge a portion of its estimated future oil production. The following table summarizes information about these additional commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.


	Aggregate Volume		Index Price ^(a)		Contract Period

Oil (volumes in Bbls):

Price swap		712,000	$	98.90		02/01/12 - 08/31/12

Price swap		150,000	$	98.90		02/01/12 - 11/30/12

Price swap		990,000	$	99.75		02/01/12 - 12/31/12

Price swap		183,000	$	98.65		01/01/13 - 03/31/13

Price swap		130,000	$	97.65		01/01/13 - 10/31/13

Price swap		110,000	$	97.40		01/01/13 - 11/30/13

Price swap		2,040,000	$	97.62		01/01/13 - 12/31/13

Price swap		1,350,000	$	95.45		01/01/14 - 03/31/14

(a)	The index prices for the oil price swaps are based on the New York Mercantile Exchange (“NYMEX”)-West Texas Intermediate monthly average futures price.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Commodity derivative contracts at March 31, 2012. The following table sets forth the Company’s outstanding derivative contracts at March 31, 2012. When aggregating multiple contracts, the weighted average contract price is disclosed.


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total

Oil Swaps: ^(a)

*2012:*

Volume (Bbl)				3,539,500		3,193,500		2,941,500		9,674,500

Price per Bbl				$94.27		$95.16		$95.07		$94.80

*2013:*

Volume (Bbl)		2,716,000		2,531,000		2,423,000		2,385,000		10,055,000

Price per Bbl		$95.48		$95.25		$94.88		$94.84		$95.12

*2014:*

Volume (Bbl)		1,692,000		339,000		339,000		337,000		2,707,000

Price per Bbl		$93.26		$84.55		$84.55		$84.51		$89.99

*2015:*

Volume (Bbl)		324,000		324,000		23,000		21,000		692,000

Price per Bbl		$84.91		$84.91		$90.05		$90.05		$85.24

*2016:*

Volume (Bbl)		21,000		21,000		21,000		18,000		81,000

Price per Bbl		$89.65		$89.65		$89.65		$89.65		$89.65

Natural Gas Swaps: ^(b)

*2012:*

Volume (MMBtu)				75,000		75,000		75,000		225,000

Price per MMBtu				$6.54		$6.54		$6.54		$6.54

(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.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Interest rate derivative contracts. The Company previously had interest rate swaps that fixed the London Interbank Offered Rate (“LIBOR”) on $300 million of its borrowings under its credit facility at 1.90 percent for three years beginning in May 2009. In May 2011, in connection with issuing additional senior notes and a review of the amounts that may be outstanding under its credit facility, the Company terminated its interest rate swaps for approximately $5.0 million. See Note I for further discussion of the Company’s credit facility.

The following table summarizes the gains and losses reported in earnings related to the commodity and interest rate derivative instruments for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
(in thousands)	2012		2011

*Loss on derivatives not designated as hedges:*

Cash (payments on) receipts from derivatives not designated as hedges:
Commodity derivatives:
Oil	$	(32,196)	$	(32,230)
Natural gas		285		5,129
Interest rate derivatives		-		(1,195)

Mark-to-market gain (loss):
Commodity derivatives:
Oil		(126,108)		(201,508)
Natural gas		(74)		(4,223)
Interest rate derivatives		-		885

Total loss on derivatives not designated as hedges	$	(158,093)	$	(233,142)

All of the Company’s derivative contracts at March 31, 2012 are expected to settle by December 31, 2016.

Note I. Debt

The Company’s debt consisted of the following at March 31, 2012 and December 31, 2011:


(in thousands)	March 31, 2012		December 31, 2011

Credit facility	$	185,000	$	583,500
8.625% unsecured senior notes due 2017		300,000		300,000
7.0% unsecured senior notes due 2021		600,000		600,000
6.5% unsecured senior notes due 2022		600,000		600,000
5.5% unsecured senior notes due 2022		600,000		-
Unamortized original issue discount, net		(3,248)		(3,359)
Less: current portion		-		-

Total long-term debt	$	2,281,752	$	2,080,141

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Credit facility. The Company’s credit facility, as amended (the “Credit Facility”), has a maturity date of April 25, 2016. The Company’s borrowing base is $2.5 billion until the next scheduled borrowing base redetermination in October 2012, and commitments from the Company’s bank group total $2.0 billion. 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, 2012) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). At March 31, 2012, the interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest margins ranging from 150 to 250 basis points and 50 to 150 basis points per annum, respectively, depending on the debt balance outstanding. At March 31, 2012, the Company paid commitment fees on the unused portion of the available commitments ranging from 37.5 to 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 its oil and natural gas properties. In addition, all of the Company’s subsidiaries are guarantors and have pledged to secure borrowings under the Credit Facility.

The credit agreement contains various restrictive covenants and compliance requirements which include:

•

maintenance of certain financial ratios, including (i) maintenance of a quarterly ratio of total debt to consolidated earnings before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and other noncash income and expenses to be no greater than 4.0 to 1.0, and (ii) maintenance of a ratio of current assets to current liabilities, excluding noncash assets and liabilities related to financial derivatives and asset retirement obligations and including the unfunded amounts under the Credit Facility, to be not less than 1.0 to 1.0;

•

limits on the incurrence of additional indebtedness and certain types of liens;

•

restrictions as to mergers, combinations and dispositions of assets; and

•

restrictions on the payment of cash dividends.

At March 31, 2012, the Company was in compliance with all of the covenants under the Credit Facility.

8.625% senior notes. In September 2009, the Company issued $300 million aggregate principal amount of 8.625% senior notes due 2017 at 98.578 percent of par (the “2017 Senior Notes”). The 2017 Senior Notes mature on October 1, 2017, and interest is paid in arrears semi-annually on April 1 and October 1. The 2017 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries.

7.0% senior notes. In December 2010, the Company issued $600 million aggregate principal amount of 7.0% senior notes due 2021 at par (the “2021 Senior Notes”). The 2021 Senior Notes mature on January 15, 2021, and interest is paid in arrears semi-annually on January 15 and July 15. The 2021 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries.

6.5% senior notes. In May 2011, the Company issued $600 million aggregate principal amount of 6.5% senior notes due 2022 at par (the “6.5% 2022 Senior Notes”). The 6.5% 2022 Senior Notes mature on January 15, 2022, and interest is paid in arrears semi-annually on January 15 and July 15. The 6.5% 2022 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries.

5.5% senior notes. In March 2012, the Company issued $600 million aggregate principal amount of 5.5% senior notes due 2022

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

at par (the “5.5% 2022 Senior Notes”). The 5.5% 2022 Senior Notes mature on October 1, 2022, and interest is paid in arrears semi-annually on October 1 and April 1, beginning on October 1, 2012. The 5.5% 2022 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries.

Future interest expense from the 2017 Senior Notes original issue discount at March 31, 2012 was as follows:


(in thousands)

Remaining 2012	$	351
2013		507
2014		557
2015		612
2016		672
Thereafter		549

Total	$	3,248

Principal maturities of debt. Principal maturities of long-term debt outstanding at March 31, 2012 were as follows:


(in thousands)
2012	$	-
2013		-
2014		-
2015		-
2016		185,000
Thereafter		2,100,000

Total	$	2,285,000

Interest expense. The following amounts have been incurred and charged to interest expense for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
(in thousands)	2012		2011
Cash payments for interest	$	51,647	$	10,395
Amortization of original issue discount (premium)		111		(114)
Amortization of deferred loan origination costs		2,706		3,543
Net changes in accruals		(18,627)		15,909

Interest costs incurred		35,837		29,733
Less: capitalized interest		-		(73)

Total interest expense	$	35,837	$	29,660

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Note J. 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 $4.6 million.

Indemnifications. The Company has agreed to indemnify its directors and officers with respect to 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.

Contractual drilling 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, 2012:


	Payments Due By Period
(in thousands)	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years

Contractual drilling commitments	$	18,770	$	9,670	$	9,100	$	-	$	-

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

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, 2012 and 2011 were approximately $1.1 million and $0.5 million, respectively.

Future minimum lease commitments under non-cancellable operating leases at March 31, 2012 were as follows:


(in thousands)

Remaining 2012	$	3,370
2013		3,862
2014		3,000
2015		2,180
2016		1,516
Thereafter		399

Total	$	14,327

Note K. 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. At March 31, 2012 and December 31, 2011, the Company had current income taxes receivable of approximately $3.0 million and $3.9 million, respectively, and current income taxes payable of approximately $1.0 million and $0.8 million, respectively.

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”), if any, and other deferred tax attributes in the United States, state, and local tax jurisdictions will be utilized prior to their expiration. At March 31, 2012 and December 31, 2011, the Company had no valuation allowances related to its deferred tax assets.

At March 31, 2012, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2009 through 2011 remain subject to examination by the major tax jurisdictions.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

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, 2012 and 2011:


	Three Months Ended March 31,
(in thousands)	2012		2011

Income (loss) from continuing operations	$	19,117	$	(30,469)
Income from discontinued operations		-		56,529
Changes in stockholders’ equity:
Excess tax benefits related to stock-based compensation		(6,781)		(17,043)

	$	12,336	$	9,017

The Company’s income tax provision (benefit) attributable to income (loss) from continuing operations consisted of the following for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
(in thousands)	2012		2011

*Current:*
U.S. federal	$	5,682	$	6,344
U.S. state and local		866		763

Total current income tax provision		6,548		7,107

*Deferred:*
U.S. federal		10,949		(32,853)
U.S. state and local		1,620		(4,723)

Total deferred income tax provision (benefit)		12,569		(37,576)

Total income tax provision (benefit) attributable to income (loss) from continuing operations	$	19,117	$	(30,469)

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

The reconciliation between the income tax expense (benefit) computed by multiplying pretax income (loss) from continuing operations by the United States federal statutory rate and the reported amounts of income tax expense (benefit) from continuing operations is as follows:


	Three Months Ended March 31,
(in thousands)	2012		2011

Income (loss) at U.S. federal statutory rate	$	17,582	$	(27,679)
State income taxes (net of federal tax effect)		1,616		(2,574)
Statutory depletion		(16)		(42)
Nondeductible expense & other		(65)		(174)

Income tax expense (benefit)	$	19,117	$	(30,469)


Effective tax rate		38.1%		38.5%

The Company’s income tax provision attributable to income from discontinued operations consisted of the following for the three months ended March 31, 2011:


(in thousands)	Three Months Ended March 31, 2011

*Current:*
U.S. federal	$	(1,192)
U.S. state and local		4

Total current income tax benefit		(1,188)

*Deferred:*
U.S. federal		50,373
U.S. state and local		7,344

Total deferred income tax provision		57,717

Total income tax provision attributable to income from discontinued operations	$	56,529

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Note L. Related party transactions

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


	Three Months Ended
	March 31,
(in thousands)	2012		2011

*Royalty interests paid to a director of the Company ^(a⁾*	$	439	$	6

*Amounts paid under consulting agreement with Steven L. Beal⁽^b)*	$	60	$	60


(in thousands)	March 31, 2012		December 31, 2011

*Amounts included in accounts payable - related parties:*

Royalty interests of a director of the Company ^(a⁾	$	145	$	11

(a)	Royalties are paid on certain properties to a partnership of which one of the Company’s directors is the general partner and owns a 3.5 percent partnership interest. The tables above summarize the amounts paid to such partnership and amounts due at period end.

(b)

On June 30, 2009, Steven L. Beal, the Company’s then-president and chief operating officer, retired from such positions. On June 9, 2009, the Company entered into a consulting agreement (the “Consulting Agreement”) with Mr. Beal, under which Mr. Beal began serving as a consultant to the Company on July 1, 2009. Either the Company or Mr. Beal may terminate the consulting relationship at any time by giving ninety days written notice to the other party; however, the Company may terminate the relationship immediately for cause. During the term of the consulting relationship, Mr. Beal will receive a consulting fee of $20,000 per month and a monthly reimbursement for his medical and dental coverage costs. If Mr. Beal dies during the term of the Consulting Agreement, his estate will receive a $60,000 lump sum payment. As part of the consulting agreement, certain of Mr. Beal’s stock-based awards were modified to permit vesting and exercise under the original terms of the stock-based awards as if Mr. Beal were still an employee of the Company while he is performing consulting services for the Company. The tables above summarize the Company’s activities pursuant to the consulting agreement with Mr. Beal.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Note M. Discontinued operations

In March 2011, the Company sold its Bakken assets for cash consideration of approximately $195.9 million. In 2011, after completion of the final post-closing adjustments, the Company recognized a pre-tax gain on the sale of assets of approximately $135.9 million; however, through the three months ended March 31, 2011, the Company’s results of operations reflected a pre-tax gain on sale of assets of approximately $142.0 million.

The Company reflected the result of operations of this divestiture as discontinued operations, rather than as a component of continuing operations. The following table represents the components of the Company’s discontinued operations for the three months ended March 31, 2011:


(in thousands)	Three Months Ended March 31, 2011
Operating revenues:
Oil sales	$	9,456
Natural gas sales		68

Total operating revenues		9,524

Operating costs and expenses:
Oil and natural gas production		1,642
Depreciation, depletion and amortization ^(a)		2,107
Accretion of discount on asset retirement obligations ^(a⁾		8

Total operating costs and expenses		3,757

Income from operations		5,767
Other income (expense):
Gain on disposition of assets, net ^(a)		141,950

Income from discontinued operations before income taxes		147,717

Income tax benefit (expense):
Current		1,188
Deferred ^(a)		(57,717)

Income from discontinued operations, net of tax	$	91,188

(a)	Represents the significant non-cash components of discontinued operations.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Note N. Net income per share

Basic net income per share is computed by dividing net income applicable to common shareholders by the weighted average number of common shares treated as outstanding for the period.

The computation of diluted net income per share reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive to income were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. These amounts include unexercised stock options and restricted stock. 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, 2012 and 2011:


	Three Months Ended March 31,
(in thousands)	2012		2011

*Weighted average common shares outstanding:*
Basic		102,854		102,242
Dilutive common stock options		481		-
Dilutive restricted stock		435		-

Diluted		103,770		102,242

The following table is a summary of the common stock options and restricted stock which were not included in the computation of diluted net income per share, as inclusion of these items would be antidilutive:


	Three Months Ended March 31,
(in thousands)	2012		2011

*Number of antidilutive common shares:*
Antidilutive common stock options		-		1,123
Antidilutive restricted stock		150		854

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Note O. Other current liabilities

The following table provides the components of the Company’s other current liabilities at March 31, 2012 and December 31, 2011:


(in thousands)	March 31, 2012		December 31, 2011

*Other current liabilities:*
Accrued production costs	$	51,707	$	47,437
Payroll related matters		16,604		18,433
Accrued interest		34,106		52,733
Asset retirement obligations		7,496		7,445
Other		21,149		16,638

Other current liabilities	$	131,062	$	142,686

Note P. Subsidiary guarantors

All of the Company’s wholly-owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. See Note I for a summary of the Company’s senior notes. 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, 2012 and December 31, 2011, and Condensed Consolidating Statements of Operations and Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2012 and 2011, 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, 2012

Unaudited

		xxxxxxxxxxxxx		xxxxxxxxxxxxx		xxxxxxxxxxxxx		xxxxxxxxxxxxx
Condensed Consolidating Balance Sheet March 31, 2012
(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
ASSETS
Accounts receivable—related parties	$	3,921,228	$	92,821	$	(4,014,049)	$	-
Other current assets		49,410		425,081		-		474,491
Oil and natural gas properties, net		-		6,669,733		-		6,669,733
Property and equipment, net		-		77,036		-		77,036
Investment in subsidiaries		2,638,458		-		(2,638,458)		-
Other long-term assets		73,000		52,349		-		125,349

Total assets	$	6,682,096	$	7,317,020	$	(6,652,507)	$	7,346,609

LIABILITIES AND EQUITY
Accounts payable - related parties	$	92,821	$	3,921,373	$	(4,014,049)	$	145
Other current liabilities		166,866		700,800		-		867,666
Other long-term liabilities		1,114,934		56,389		-		1,171,323
Long-term debt		2,281,752		-		-		2,281,752
Equity		3,025,723		2,638,458		(2,638,458)		3,025,723

Total liabilities and equity	$	6,682,096	$	7,317,020	$	(6,652,507)	$	7,346,609

		xxxxxxxxxxxxx		xxxxxxxxxxxxx		xxxxxxxxxxxxx		xxxxxxxxxxxxx
Condensed Consolidating Balance Sheet December 31, 2011
(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
ASSETS
Accounts receivable - related parties	$	4,983,923	$	706,905	$	(5,690,828)	$	-
Other current assets		34,229		376,794		-		411,023
Oil and natural gas properties, net		-		6,230,915		-		6,230,915
Property and equipment, net		-		59,203		-		59,203
Investment in subsidiaries		2,394,050		-		(2,394,050)		-
Other long-term assets		73,587		74,848		-		148,435

Total assets	$	7,485,789	$	7,448,665	$	(8,084,878)	$	6,849,576

LIABILITIES AND EQUITY
Accounts payable - related parties	$	1,271,524	$	4,419,315	$	(5,690,828)	$	11
Other current liabilities		118,836		582,630		-		701,466
Other long-term liabilities		1,034,549		52,670		-		1,087,219
Long-term debt		2,080,141		-		-		2,080,141
Equity		2,980,739		2,394,050		(2,394,050)		2,980,739

Total liabilities and equity	$	7,485,789	$	7,448,665	$	(8,084,878)	$	6,849,576

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited


Condensed Consolidating Statement of Operations Three Months Ended March 31, 2012
(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
Total operating revenues	$	-	$	507,805	$	-	$	507,805
Total operating costs and expenses		(158,338)		(262,128)		-		(420,466)

Income (loss) from operations		(158,338)		245,677		-		87,339
Interest expense		(35,837)		-		-		(35,837)
Other, net		244,409		(1,269)		(244,408)		(1,268)

Income before income taxes		50,234		244,408		(244,408)		50,234
Income tax expense		(19,117)		-		-		(19,117)

Net income	$	31,117	$	244,408	$	(244,408)	$	31,117


Condensed Consolidating Statement of Operations Three Months Ended March 31, 2011
(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
Total operating revenues	$	-	$	360,840	$	-	$	360,840
Total operating costs and expenses		(230,863)		(179,047)		-		(409,910)

Income (loss) from continuing operations		(230,863)		181,793		-		(49,070)
Interest expense		(29,660)		-		-		(29,660)
Other, net		329,158		(552)		(328,958)		(352)

Income (loss) from continuing operations before income taxes		68,635		181,241		(328,958)		(79,082)
Income tax benefit		30,469		-		-		30,469

Income (loss) from continuing operations	$	99,104	$	181,241	$	(328,958)	$	(48,613)
Income (loss) from discontinued operations, net of tax		(56,529)		147,717		-		91,188

Net income	$	42,575	$	328,958	$	(328,958)	$	42,575

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited


Condensed Consolidating Statement of Cash Flows Three Months Ended March 31, 2012
(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
Net cash flows provided by (used in) operating activities	$	(167,276)	$	513,181	$	-	$	345,905
Net cash flows used in investing activities		(31,913)		(543,834)		-		(575,747)
Net cash flows provided by financing activities		199,189		30,917		-		230,106

Net increase in cash and cash equivalents		-		264		-		264
Cash and cash equivalents at beginning of period		-		342		-		342

Cash and cash equivalents at end of period	$	-	$	606	$	-	$	606


Condensed Consolidating Statement of Cash Flows Three Months Ended March 31, 2011
(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
Net cash flows provided by operating activities	$	19,510	$	145,975	$	-	$	165,485
Net cash flows used in investing activities		(26,901)		(177,709)		-		(204,610)
Net cash flows provided by financing activities		7,894		31,755		-		39,649

Net increase in cash and cash equivalents		503		21		-		524
Cash and cash equivalents at beginning of period		46		338		-		384

Cash and cash equivalents at end of period	$	549	$	359	$	-	$	908

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Note Q. Subsequent events

New commodity derivative contracts. In April 2012, the Company entered into the following oil price swaps to hedge additional amounts of its estimated future oil production:


	Aggregate Volume		Index Price ^(a)		Contract Period

Oil (volumes in Bbls):
Price swap		145,000	$	103.65	05/01/2012 - 08/31/2012
Price swap		150,000	$	104.40	05/01/2012 - 10/31/2012
Price swap		1,000,000	$	104.00	05/01/2012 - 12/31/2012
Price swap		230,000	$	104.30	01/01/2013 - 08/31/2013
Price swap		180,000	$	103.30	01/01/2013 - 09/30/2013
Price swap		900,000	$	102.86	01/01/2013 - 12/31/2013
Price swap		900,000	$	98.81	01/01/2014 - 06/30/2014
Price swap		450,000	$	98.52	04/01/2014 - 06/30/2014

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

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2012

Unaudited

Note R. Supplementary information

Capitalized costs


(in thousands)	March 31, 2012		December 31, 2011

*Oil and natural gas properties:*
Proved	$	7,122,635	$	6,551,396
Unproved		797,057		796,064
Less: accumulated depletion		(1,249,959)		(1,116,545)

Net capitalized costs for oil and natural gas properties	$	6,669,733	$	6,230,915

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


	Three Months Ended March 31,
(in thousands)	2012		2011

Property acquisition costs:
Proved	$	160,047	$	65,918
Unproved		39,356		57,208
Exploration		184,483		90,566
Development		194,731		193,717

Total costs incurred for oil and natural gas properties	$	578,617	$	407,409

(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)	2012		2011

Proved property acquisition costs	$	2,050	$	148
Exploration costs		798		320
Development costs		44		(5)

Total	$	2,892	$	463

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

The following discussion is intended to assist you 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 a result of the acquisitions and divestures discussed below, many comparisons between periods will be difficult or impossible.

In February 2012, we acquired certain producing and non-producing assets from Petroleum Development Corporation (the “PDC Acquisition”) for cash consideration of approximately $184.4 million, subject to customary post-closing adjustments. The PDC Acquisition was primarily funded with borrowings under our credit facility. The results of operations prior to March 2012 do not include results from the PDC Acquisition.

In November 2011, we acquired three entities affiliated with OGX Holdings II, LLC (collectively the “OGX Acquisition”) for cash consideration of approximately $252.0 million. The OGX Acquisition was primarily funded with borrowings under our credit facility. The results of operations prior to December 2011 do not include results from the OGX Acquisition.

In March 2011, we sold our Bakken assets for cash consideration of approximately $195.9 million. In 2011, after completion of the final post-closing adjustments, we recognized a pre-tax gain on the sale of assets of approximately $135.9 million; however, through the three months ended March 31, 2011, our results of operations reflected a pre-tax gain on sale of assets of approximately $142.0 million. We have reflected the results of operations of these divested assets as discontinued operations, rather than as a component of continuing operations. See Note M of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding these divestitures and their discontinued operations. For the first quarter of 2011, these assets produced an average of 1,369 Boe per day.

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

Overview

We are an independent oil and natural gas company engaged in the acquisition, development and exploration of producing oil and natural gas properties. Our core operations are primarily focused in the Permian Basin of Southeast New Mexico and West Texas. We refer to our three core operating areas as the (i) New Mexico Shelf, where we primarily target the Yeso and Lower Abo formations, (ii) Delaware Basin, where we primarily target the Bone Spring formation (which includes the Avalon Shale and the Bone Springs sands) and the Wolfcamp shale, and (iii) Texas Permian, where we primarily target the Wolfberry, a term applied to the combined Wolfcamp and Spraberry horizons. Oil comprised 61.7 percent of our 386.5 MMBoe of estimated proved reserves at December 31, 2011 and 60.9 percent of our 6.9 MMBoe of production for the three months ended March 31, 2012. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 93.0 percent of our proved developed producing PV-10 and 78.8 percent of our 5,504 gross wells at December 31, 2011. 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.

Financial and Operating Performance

Our financial and operating performance for the three months ended March 31, 2012, as compared to the three months ended March 31, 2011, included the following highlights:

•

Net income was $31.1 million ($0.30 per diluted share) for the first three months of 2012, as compared to net income of $42.6 million ($0.42 per diluted share) during the three months ended March 31, 2011. The decrease in earnings is primarily due to:

$91.2 million income from discontinued operations, net of tax related to the sale of our Bakken assets in the first quarter of 2011;

$45.6 million increase in depreciation, depletion and amortization (“DD&A”) expense, primarily due to increased production in 2012;

$28.5 million increase in oil and natural gas production costs due in part to increased (i) production in 2012, (ii) labor costs, (iii) routine environmental-related costs and (iv) oil and natural gas revenues in 2012 that directly increased our oil and natural gas production taxes; and

$6.1 million increase in interest expense due to (i) a 28 percent increase in the weighted average debt balance outstanding between the periods primarily related to acquisitions, (ii) the May 2011 $600 million issuance of our 6.5% senior notes due 2022, (iii) the March 2012 $600 million issuance of our 5.5% senior notes due 2022 and (iv) the amortization of capitalized loan costs associated with our senior notes;

partially offset by:

$147.0 million increase in oil and natural gas revenues as a result of a 36 percent increase in production and a 4 percent increase in commodity price realizations per Boe (excluding the effects of derivative activities); and

$75.0 million decrease in net losses on derivatives not designated as hedges.

•

Average daily sales volumes from continuing operations increased by 34 percent from 56,722 Boe per day during the first quarter of 2011 to 76,031 Boe per day during the first quarter of 2012. The increase is primarily attributable to our successful drilling efforts during 2011 and 2012 and our OGX and PDC Acquisitions.

•

Net cash provided by operating activities increased by approximately $180.4 million to $345.9 million for the first quarter of 2012, as compared to $165.5 million in the first quarter of 2011, primarily due to (i) the increased oil and natural gas revenues and (ii) positive variances in working capital changes, offset by increases in related oil and natural gas production costs and other cash related costs.

•

Long-term debt increased by approximately $201.6 million during the first quarter of 2012, primarily as a result of the PDC Acquisition in February 2012.

•

At March 31, 2012 our availability under our credit facility was approximately $1.8 billion.

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;

•

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 United States economy impact,

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 economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Note H of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commodity derivative positions at March 31, 2012.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, oil prices were moderately higher during the comparable periods of 2012 measured against 2011, while natural gas prices were significantly lower. The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three months ended March 31, 2012 and 2011, as well as the high and low NYMEX prices for the same periods:


	Three Months Ended March 31,
	2012		2011

Average NYMEX prices:
Oil (Bbl)	$	102.88	$	94.26
Natural gas (MMBtu)	$	2.52	$	4.20

High and Low NYMEX prices:
*Oil (Bbl):*
High	$	109.77	$	106.72
Low	$	96.36	$	84.32

*Natural gas (MMBtu):*
High	$	3.10	$	4.74
Low	$	2.13	$	3.78

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $106.16 and $101.02 per Bbl and $2.37 and $1.91 per MMBtu, respectively, during the period from March 31, 2012 to May 1, 2012. At May 1, 2012, the NYMEX oil price and NYMEX natural gas price were $106.16 per Bbl and $2.37 per MMBtu, respectively.

Recent Events

Senior notes issuance. In March 2012, we issued $600 million aggregate principal amount of 5.5% senior notes due 2022 at par, for which we received net proceeds of approximately $590.0 million. We used the net proceeds to repay a portion of the borrowings under our credit facility, which increased our liquidity for future activities.

PDC Acquisition. In February 2012, we completed the PDC Acquisition for cash consideration of approximately $184.4 million, subject to customary post-closing adjustments. The PDC Acquisition was primarily funded with borrowings under our credit facility. The results of operations prior to March 2012 do not include results from the PDC Acquisition.

2012 capital budget. In November 2011, we announced our 2012 capital budget of approximately $1.3 billion, which was subsequently increased to $1.37 billion in connection with the PDC Acquisition (exclusive of the $184.4 million PDC Acquisition purchase price). We expect that our 2012 capital expenditures can be funded substantially within our cash flow, based on current commodity prices and our expectations of capital costs. We take a longer-term view on spending substantially within our cash flow, and our spending during any specific period may exceed our cash flow for that period. However, our capital budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in our drilling and completion costs, we may reduce our capital spending program to be substantially within our cash flow.

Our capital budget does not include acquisitions (other than the customary purchase of leasehold acreage). The following is a summary of our 2012 capital budget:


(in millions)	2012 Capital Budget
Drilling and completion costs:
New Mexico Shelf	$	496
Delaware Basin		420
Texas Permian		336
Acquisition of leasehold acreage and other property interests, geological and geophysical and other		58
Facilities and other capital in our core operating areas		55

Total	$	1,365

Derivative Financial Instruments

Derivative financial instrument exposure. At March 31, 2012, the fair value of our financial derivatives was a net liability of $205.0 million. All of our counterparties to these financial derivatives are parties to our credit facility and have their outstanding debt commitments and derivative exposures collateralized pursuant to our credit facility. Under the terms of our financial derivative instruments and their collateralization under our credit facility, we do not have exposure to potential “margin calls” on our financial derivative 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 three months ended March 31, 2012, we entered into additional commodity derivative contracts to hedge a portion of our estimated future oil production. The following table summarizes information about these additional commodity derivative contracts for the three months ended March 31, 2012. When aggregating multiple contracts, the weighted average contract price is disclosed.


	Aggregate Volume		Index Price ^(a)		Contract Period

Oil (volumes in Bbls):
Price swap		712,000	$	98.90	02/01/12 - 08/31/12
Price swap		150,000	$	98.90	02/01/12 - 11/30/12
Price swap		990,000	$	99.75	02/01/12 - 12/31/12
Price swap		183,000	$	98.65	01/01/13 - 03/31/13
Price swap		130,000	$	97.65	01/01/13 - 10/31/13
Price swap		110,000	$	97.40	01/01/13 - 11/30/13
Price swap		2,040,000	$	97.62	01/01/13 - 12/31/13
Price swap		1,350,000	$	95.45	01/01/14 - 03/31/14

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

In April 2012, we entered into the following oil price swaps to hedge additional amounts of our estimated future oil production:


	Aggregate Volume		Index Price ^(a)		Contract Period
Oil (volumes in Bbls):
Price swap		145,000	$	103.65	05/01/2012 - 08/31/2012
Price swap		150,000	$	104.40	05/01/2012 - 10/31/2012
Price swap		1,000,000	$	104.00	05/01/2012 - 12/31/2012
Price swap		230,000	$	104.30	01/01/2013 - 08/31/2013
Price swap		180,000	$	103.30	01/01/2013 - 09/30/2013
Price swap		900,000	$	102.86	01/01/2013 - 12/31/2013
Price swap		900,000	$	98.81	01/01/2014 - 06/30/2014
Price swap		450,000	$	98.52	04/01/2014 - 06/30/2014

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

Results of Operations

The following table sets forth summary information concerning our production and operating data from continuing operations for the three months ended March 31, 2012 and 2011. The table below excludes production and operating data that we have classified as discontinued operations, which is more fully described in Note M of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).” The actual historical data in this table excludes results from (i) the PDC Acquisition for periods prior to March 2012 and (ii) the OGX Acquisition for periods prior to December 2011. Because of normal production declines, increased or decreased drilling activities and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.


	Three Months Ended March 31,
	2012		2011
Production and operating data:
Net production volumes:
Oil (MBbl)		4,214		3,110
Natural gas (MMcf)		16,229		11,970
Total (MBoe)		6,919		5,105

Average daily production volumes:
Oil (Bbl)		46,308		34,556
Natural gas (Mcf)		178,341		133,000
Total (Boe)		76,032		56,722

Average prices:
Oil, without derivatives (Bbl)	$	98.16	$	90.81
Oil, with derivatives (Bbl) ^(a⁾	$	90.52	$	80.45
Natural gas, without derivatives (Mcf)	$	5.80	$	6.55
Natural gas, with derivatives (Mcf) ^(a⁾	$	5.82	$	6.98
Total, without derivatives (Boe)	$	73.39	$	70.68
Total, with derivatives (Boe) ^(a⁾	$	68.78	$	65.37

Operating costs and expenses per Boe:
Lease operating expenses and workover costs	$	7.28	$	6.67
Oil and natural gas taxes	$	6.04	$	5.80
Depreciation, depletion and amortization	$	19.64	$	17.69
General and administrative	$	3.96	$	4.19

(a)

Includes the effect of 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 loss on derivatives not designated as hedges as reported in the statements of operations:


	Three Months Ended March 31,
(in thousands)	2012		2011
Loss on derivatives not designated as hedges:
Cash payments on oil derivatives	$	(32,196)	$	(32,230)
Cash receipts from natural gas derivatives		285		5,129
Cash payments on interest rate derivatives		-		(1,195)
Unrealized mark-to-market loss on commodity and interest rate derivatives		(126,182)		(204,846)

Loss on derivatives not designated as hedges	$	(158,093)	$	(233,142)

The presentation of average prices with derivatives is a non-GAAP measure as a result of including the cash (payments on) receipts from commodity derivatives that are presented in loss on derivatives not designated as hedges in the statements of operations. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community.

The following table sets forth summary information from our discontinued operations concerning our production and operating data for the three months ended March 31, 2011. The discontinued operations presentation is the result of reclassifying the results of operations from our March 2011 Bakken divestiture, which is more fully described in Note M of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).”


	Three Months Ended March 31, 2011
Production and operating data:

Net production volumes:
Oil (MBbl)			117
Natural gas (MMcf)			37
Total (MBoe)			123

Average daily production volumes:
Oil (Bbl)			1,300
Natural gas (Mcf)			411
Total (Boe)			1,369

Average prices:
Oil, without derivatives (Bbl)		$	80.82
Oil, with derivatives (Bbl)		$	80.82
Natural gas, without derivatives (Mcf)		$	1.84
Natural gas, with derivatives (Mcf)		$	1.84
Total, without derivatives (Boe)		$	77.43
Total, with derivatives (Boe)		$	77.43

Operating costs and expenses per Boe:
Lease operating expenses and workover costs		$	3.85
Oil and natural gas taxes		$	9.50
Depreciation, depletion and amortization		$	17.13

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

Oil and natural gas revenues. Revenue from oil and natural gas operations was $507.8 million for the three months ended March 31, 2012, an increase of $147.0 million (41 percent) from $360.8 million for the three months ended March 31, 2011. This increase was primarily due to increases in realized oil prices and increased production due to successful drilling efforts during 2011 and 2012 and to a lesser extent production from the OGX Acquisition which closed in November 2011. Specific factors affecting oil and natural gas revenues include the following:

•

total oil production was 4,214 MBbl for the three months ended March 31, 2012, an increase of 1,104 MBbl (35 percent) from 3,110 MBbl for the three months ended March 31, 2011;

•

average realized oil price (excluding the effects of derivative activities) was $98.16 per Bbl during the three months ended March 31, 2012, an increase of 8 percent from $90.81 per Bbl during the three months ended March 31, 2011;

•

total natural gas production was 16,229 MMcf for the three months ended March 31, 2012, an increase of 4,259 MMcf (36 percent) from 11,970 MMcf for the three months ended March 31, 2011; and

•

average realized natural gas price (excluding the effects of derivative activities) was $5.80 per Mcf during the three months ended March 31, 2012, a decrease of 11 percent from $6.55 per Mcf during the three months ended March 31, 2011. Our natural gas prices have been significantly higher than the related NYMEX prices primarily due to the value of the natural gas liquids in our liquids-rich natural gas stream.

Production expenses. The following table provides the components of our total oil and natural gas production costs for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
	2012				2011
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe

Lease operating expenses	$	48,342	$	6.99	$	33,913	$	6.65
Taxes:
Ad valorem		3,088		0.45		2,666		0.52
Production		38,687		5.59		26,952		5.28
Workover costs		2,033		0.29		127		0.02

Total oil and natural gas production expenses	$	92,150	$	13.32	$	63,658	$	12.47

Among the cost components of production expenses, 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 $48.3 million ($6.99 per Boe) for the three months ended March 31, 2012, which was an increase of $14.4 million (42 percent) from $33.9 million ($6.65 per Boe) for the three months ended March 31, 2011. The increase in lease operating expenses was primarily due to (i) our wells successfully drilled and completed in 2011 and 2012 and (ii) an increase in cost of services, primarily labor related, due to the increased demand for services and related labor in the Permian Basin. The increase in lease operating expenses per Boe was primarily due to (i) cost increases in services, primarily labor related, (ii) incurrence of higher than normal routine environmental related costs, offset in part by additional production from our wells successfully drilled and completed in 2011 and 2012 where we are receiving benefits from economies of scale.

Ad valorem taxes have increased primarily as a result of increased valuations of our Texas properties and the increase in the number of wells primarily associated with our 2011 and 2012 drilling activity in our Texas Permian area.

Production taxes per unit of production were $5.59 per Boe during the three months ended March 31, 2012, an increase of 6 percent from $5.28 per Boe during the three months ended March 31, 2011. The increase was directly related to the increase in

commodity prices and our increase in oil and natural gas revenues related to increased volumes. Over the same period, our per Boe prices (excluding the effects of derivatives) increased 4 percent.

Workover expenses were approximately $2.0 million and $0.1 million for the three months ended March 31, 2012 and 2011, respectively. The 2012 amounts related primarily to workovers in the New Mexico Shelf and Texas Permian areas, while the 2011 amounts related primarily to activity in the Texas Permian area performed to increase production.

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
(in thousands)	2012		2011

Geological and geophysical	$	2,877	$	588
Exploratory dry holes		2,982		12
Leasehold abandonments and other		120		126

Total exploration and abandonments	$	5,979	$	726

Our geological and geophysical expense, which primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, was approximately $2.9 million and $0.6 million, primarily relating to our Delaware Basin and Texas Permian areas, for the three months ended March 31, 2012 and 2011, respectively.

Our exploratory dry hole expense during the three months ended March 31, 2012 was primarily related to expensing an unsuccessful lateral due to mechanical issues in the Delaware Basin.

For the three months ended March 31, 2012, we recorded approximately $0.1 million of leasehold abandonments, which related to non-core prospects in our New Mexico Shelf area. For the three months ended March 31, 2011, we recorded approximately $0.1 million of leasehold abandonments, which related to non-core prospects in our Texas Permian area.

Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
	2012				2011
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe

Depletion of proved oil and natural gas properties	$	133,167	$	19.25	$	88,943	$	17.42
Depreciation of other property and equipment		2,315		0.33		958		0.19
Amortization of intangible asset - operating rights		387		0.06		387		0.08

Total depletion, depreciation and amortization	$	135,869	$	19.64	$	90,288	$	17.69


Oil price used to estimate proved oil reserves at period end	$	94.65			$	80.04
Natural gas price used to estimate proved natural gas reserves at period end	$	3.73			$	4.11

Depletion of proved oil and natural gas properties was $133.2 million ($19.25 per Boe) for the three months ended March 31, 2012, an increase of $44.3 million (50 percent) from $88.9 million ($17.42 per Boe) for the three months ended March 31, 2011. The increase in depletion expense was primarily due to capitalized costs associated with new wells that were successfully drilled and completed in 2011 and 2012, offset in part by the increase in the oil prices between the periods utilized to determine proved reserves.

The amortization of the intangible asset is a result of the value assigned to the operating rights that we acquired in the July 2008 Henry Entities acquisition. The intangible asset is currently being amortized over an estimated life of 25 years.

General and administrative expenses. The following table provides components of our general and administrative expenses for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
	2012				2011
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe

General and administrative expenses	$	25,091	$	3.62	$	19,511	$	3.82
Non-cash stock-based compensation		6,128		0.89		4,468		0.88
Less: Third-party operating fee reimbursements		(3,832)		(0.55)		(2,587)		(0.51)

Total general and administrative expenses		$ 27,387		$ 3.96		$ 21,392		$ 4.19

Total general and administrative expenses were $27.4 million ($3.96 per Boe) for the three months ended March 31, 2012, an increase of $6.0 million (28 percent) from $21.4 million ($4.19 per Boe) for the three months ended March 31, 2011. The increase in general and administrative expenses was primarily due to an increase in (i) the number of employees and related personnel expenses to handle our increased activities and (ii) non-cash stock-based compensation awards. The decrease in total general and administrative expenses per Boe was primarily due to (i) increased production from our wells successfully drilled and completed in 2011 and 2012 and (ii) additional production from our OGX Acquisition for which we added no new personnel.

As the operator of certain oil and natural gas properties in which we own an interest, we earn overhead reimbursements during the drilling and production phases of the property. We earned reimbursements of $3.8 million and $2.6 million during the three months ended March 31, 2012 and 2011, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations.

Loss on derivatives not designated as hedges. The following table sets forth the cash settlements and the non-cash mark-to-market adjustments for the derivative contracts not designated as hedges for the three months ended March 31, 2012 and 2011:


	Three Months Ended
	March 31,
(in thousands)	2012		2011

*Cash payments (receipts):*
Commodity derivatives - oil	$	32,196	$	32,230
Commodity derivatives - natural gas		(285)		(5,129)
Financial derivatives - interest		-		1,195
*Mark-to-market (gain) loss:*
Commodity derivatives - oil		126,108		201,508
Commodity derivatives - natural gas		74		4,223
Financial derivatives - interest		-		(885)

Loss on derivatives not designated as hedges	$	158,093	$	233,142

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which can be volatile to our earnings. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.

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, 2012 and 2011:


	Three Months Ended
	March 31,
(dollars in thousands)	2012		2011

Interest expense	$	35,837	$	29,660

Weighted average interest rate		5.8%		5.8%

Weighted average debt balance	$	2,187,544	$	1,710,406

The increase in weighted average debt balance during the three months ended March 31, 2012 was due primarily to borrowings for the OGX Acquisition in December 2011, and to a lesser extent, the PDC Acquisition in February 2012. The increase in interest expense was due to (i) the May 2011 issuance of our 6.5% senior notes due 2021 and (ii) the amortization of capitalized loan costs associated with debt financing.

Income tax provisions. We recorded an income tax expense of $19.1 million and an income tax benefit of $30.5 million for the three months ended March 31, 2012 and 2011, respectively. The effective income tax rate for the three months ended March 31, 2012 and 2011 was 38.1 percent and 38.5 percent, respectively.

Income from discontinued operations, net of tax. In March 2011, we sold our Bakken assets for cash consideration of approximately $195.9 million. In 2011, after completion of the final post-closing adjustments, we recognized a pre-tax gain on the sale of assets of approximately $135.9 million; however, through the three months ended March 31, 2011, our results of operations reflected a pre-tax gain on sale of assets of approximately $142.0 million.

The results of operations of these assets and the related gain on disposition are reported as discontinued operations in the accompanying consolidated statements of operations, described in more detail in Note M of the Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).”

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 or 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, 2012 and 2011 totaled $378.4 million and $284.0 million, respectively. The primary reason for the differences in the costs incurred and cash flow expenditures is the timing of payments. The 2012 expenditures were funded in part from borrowings under our credit facility.

In November 2011, we announced our 2012 capital budget of approximately $1.3 billion, which was subsequently increased to $1.37 billion in connection with the PDC Acquisition (exclusive of the $184.4 million PDC Acquisition purchase price). We expect to fund our 2012 capital budget substantially within our cash flow, based on current commodity prices and our expectations of capital costs.

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

Other than the customary purchase of leasehold acreage, our 2012 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.

Acquisitions. Our expenditures for acquisitions of proved and unproved properties during the three months ended March 31, 2012 and 2011 totaled approximately $199.4 million and $123.1 million, respectively. The acquisitions of proved properties during the three months ended March 31, 2012 primarily relate to additional Texas Permian assets. Expenditures for leasehold acreage acquisitions (which are expenditures we generally provide for in the budget) included in the total above were approximately $9.7 million and $27.8 million for the three months ended March 31, 2012 and 2011, respectively.

Divestitures. In March 2011, we sold our Bakken assets for cash consideration of approximately $195.9 million. In 2011, after completion of the final post-closing adjustments, we recognized a pre-tax gain on the sale of assets of approximately $135.9 million; however, through the three months ended March 31, 2011, our results of operations reflected a pre-tax gain on sale of assets of approximately $142.0 million. For 2011, these assets produced an average of approximately 1,369 Boe per day, of which approximately 95 percent was oil. We used the net proceeds from this divestiture to initially repay a portion of the outstanding borrowings under our credit facility.

Contractual obligations. Our contractual obligations include long-term debt, cash interest expense on debt, operating lease obligations, drilling commitments, employment agreements with officers, derivative liabilities and other obligations. Since December 31, 2011, the material changes in our contractual obligations included a $201.6 million increase in outstanding long-term debt, a $261.3 million increase in cash interest expense on debt and a $116.6 million increase in our net commodity derivative liability. See Note I of the 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, 2012.

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 currently believe that our cash flow will substantially meet both our short-term working capital requirements

and our current 2012 capital expenditure plans. We believe that we have adequate availability under our credit facility to fund any cash flow deficits, though we could reduce our capital spending program to remain substantially within our cash flow.

The following table summarizes our net increase in cash and cash equivalents for the three months ended March 31, 2012 and 2011:


	Three Months Ended
	March 31,
(in thousands)	2012		2011
Net cash provided by operating activities	$	345,905	$	165,485
Net cash used in investing activities		(575,747)		(204,610)
Net cash provided by financing activities		230,106		39,649

Net increase in cash and cash equivalents	$	264	$	524

Cash flow from operating activities. The increase in operating cash flows during the three months ended March 31, 2012 over 2011 was principally due to increases in our oil and natural gas production as a result of our (i) exploration and development program and (ii) increases in average realized oil prices, offset by increases in oil and natural gas production costs.

Our net cash provided by operating activities also includes a reduction of $5.7 million and $89.6 million for the three months ended March 31, 2012 and 2011, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

Cash flow used in investing activities. During the three months ended March 31, 2012 and 2011, we invested $541.7 million and $354.2 million, respectively, for capital expenditures on oil and natural gas properties. Cash flows used in investing activities were higher during the three months ended March 31, 2012 as compared to 2011, due to an increase in our capital expenditures on oil and natural gas properties and a decrease in the proceeds from the sale of assets.

Cash flow from financing activities. During the three months ended March 31, 2012 and 2011 we completed the following significant activities:

•

In March 2012, we issued $600 million in aggregate principal amount of 5.5% senior notes due 2022 at par, for which we received net proceeds of approximately $590.0 million. We used the net proceeds to repay a portion of the borrowings under our credit facility, which increased our liquidity for future activities.

•

In March 2011, we sold our Bakken assets for cash consideration of approximately $195.9 million.

Our credit facility, as amended, has a maturity date of April 25, 2016. Our borrowing base is $2.5 billion until the next scheduled borrowing base redetermination in October 2012, and commitments from our bank group total $2.0 billion. 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. At March 31, 2012, we had no letters of credit outstanding under the credit facility, and our availability to borrow additional funds was approximately $1.8 billion based on bank commitments of $2.0 billion.

Advances on our 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, 2012) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). The credit facility’s interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest margins ranging from 150 to 250 basis points and 50 to 150 basis points, respectively, per annum depending on the debt balance outstanding. We pay commitment fees on the unused portion of the available commitment ranging from 37.5 to 50 basis points per annum, depending on utilization of the commitments.

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. Over the last three years, we have demonstrated our use of the capital markets by issuing common stock in public offerings and private placements and issuing senior unsecured debt. However, there are no assurances that we can access the capital markets to obtain additional funding, if needed, and at what cost and terms. 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.

Liquidity. Our principal sources of short-term liquidity are cash on hand and available borrowing capacity under our credit facility. At March 31, 2012, we had $0.6 million of cash on hand.

At March 31, 2012, the commitments under our credit facility were $2.0 billion, which provided us with approximately $1.8 billion of available borrowing capacity. Upon a redetermination, our $2.5 billion borrowing base could be substantially reduced. There is no assurance that our borrowing base will not be reduced, which could affect our liquidity.

Debt ratings. We receive debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”), which are subject to regular reviews. S&P’s corporate rating for us is “BB+” with a stable outlook. Moody’s corporate rating for us is “Ba3” with a positive outlook. S&P and Moody’s consider many factors in determining our ratings including: production growth opportunities, liquidity, debt levels and asset and reserve mix. A reduction in our debt ratings could negatively affect our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.

Book capitalization and current ratio. Our book capitalization at March 31, 2012 was $5.3 billion, consisting of debt of $2.3 billion and stockholders’ equity of $3.0 billion. Our debt to book capitalization was 43 percent and 41 percent at March 31, 2012 and December 31, 2011, respectively. Our ratio of current assets to current liabilities was 0.55 to 1.0 at March 31, 2012 as compared to 0.59 to 1.0 at December 31, 2011.

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, 2012, we received an average of $98.16 per barrel of oil and $5.80 per Mcf of natural gas before consideration of commodity derivative contracts compared to $90.81 per barrel of oil and $6.55 per Mcf of natural gas in the three months ended March 31, 2011. 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 that has continued, oil prices have increased significantly. The higher oil price 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.

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, valuation of stock-based compensation, valuation of business combinations and valuation of financial derivative instruments. 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, 2012. See our disclosure of critical accounting policies in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the United States Securities and Exchange Commission (the “SEC”) on February 24, 2012.

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, 2011.

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 December 31, 2011, 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.

We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note H of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative activities.

We are closely monitoring the European debt crisis, which could negatively impact the U.S. debt markets. If further deterioration occurs, it could impair our ability to raise debt, access our credit facility and collect hedging proceeds from our derivative counterparties.

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 securities. 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, 2012, would have increased the net unrealized loss on our commodity price risk management contracts by approximately $230.9 million.

At March 31, 2012, we had (i) oil price swaps that settle on a monthly basis covering future oil production from April 1, 2012 through December 31, 2016 and (ii) natural gas price swaps, natural gas price collars and natural gas basis swaps covering future natural gas production from April 1, 2012 to December 31, 2012, see Note H of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on the commodity derivative instruments. The average NYMEX oil price and average NYMEX natural gas prices for the three months ended March 31, 2012, was $102.88 per Bbl and $2.52 per MMBtu, respectively. At May 1, 2012, the NYMEX oil price and NYMEX natural gas price were $106.16 per Bbl and $2.37 per MMBtu, respectively. A decrease in the average NYMEX oil and natural gas prices below those at March 31, 2012, would decrease the fair value liability of our commodity derivative contracts from their recorded balance at March 31, 2012. 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 prices above those at March 31, 2012, would increase the fair value liability of our commodity derivative contracts from their recorded balance at March 31, 2012. The potential increase in our fair value liability would be recorded in earnings as an unrealized loss. 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 in the past 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 commitments.

We had total indebtedness of $185.0 million outstanding under our credit facility at March 31, 2012. The impact of a 1 percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $1.9 million.

The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method during the three months ended March 31, 2012. During the three months ended March 31, 2012, we were party to commodity derivative instruments. See Note H 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, 2012:


(in thousands)	Commodity Derivative Instruments Net Liabilities^(a)
Fair value of contracts outstanding at December 31, 2011	$	(78,830	)
Changes in fair values ^(b⁾		(158,093	)
Contract maturities		31,912

Fair value of contracts outstanding at March 31, 2012	$	(205,011	)

(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, 2012 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 a party to 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. We will continue to evaluate proceedings and claims involving us on a quarter-by-quarter basis and will establish and adjust any reserves as appropriate to reflect our assessment of the then current status of the matters.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2011, under the headings “Item 1. Business – Competition,” “— Marketing Arrangements” and “— Applicable Laws and Regulations,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” which risks could materially affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2011. The risks described in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

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


					Total number		Maximum
Period	Total number of shares withheld ^(a)		Average price per share		of shares purchased as part of publicly announced plans		number of shares that may yet be purchased under the plan

January 1, 2012 - January 31, 2012		2,022	$	101.98		-
February 1, 2012 - February 29, 2012		16,261	$	112.65		-
March 1, 2012 - March 31, 2012		-	$	-		-

(a)	Represents shares that were withheld by us to satisfy tax withholding obligations of certain of our officers and key employees 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).

4.2		Sixth Supplemental Indenture, dated March 12, 2012, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).

4.3		Form of 5.5% Senior Notes due 2022 (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).

10.1**		Indemnification Agreement, dated January 10, 2012, by and between Concho Resources Inc. and Gary A. Merriman (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on January 11, 2012 and incorporated herein by reference).

10.2**		Employment Agreement, dated March 19, 2012, by and between Concho Resources Inc. and Steven H. Pruett (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 22, 2012 and incorporated herein by reference).

10.3**		Indemnification Agreement, dated March 19, 2012, by and between Concho Resources Inc. and Steven H. Pruett (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on March 22, 2012 and incorporated herein by reference).

10.4		Eighth Amendment to Amended and Restated Credit Agreement, dated as of April 12, 2012, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 16, 2012, 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.

101.INS (a)		XBRL Instance Document.

101.SCH (a)		XBRL Schema Document.

101.CAL (a)		XBRL Calculation Linkbase Document.

101.DEF (a)		XBRL Definition Linkbase Document.

101.LAB (a)		XBRL Labels Linkbase Document.

101.PRE (a)		XBRL Presentation Linkbase Document.

(a)	Filed herewith.

(b)	Furnished herewith.

**	Management contract or compensatory plan or arrangement.

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 3, 2012	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
			Senior Vice President, Chief Financial Officer and Treasurer
			(Principal Financial Officer)

		By

			/s/ Don O. McCormack


			Don O. McCormack
			Vice President and Chief Accounting Officer
			(Principal 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).

4.2		Sixth Supplemental Indenture, dated March 12, 2012, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company's Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).

4.3		Form of 5.5% Senior Notes due 2022 (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).

10.1**		Indemnification Agreement, dated January 10, 2012, by and between Concho Resources Inc. and Gary A. Merriman (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on January 11, 2012 and incorporated herein by reference).

10.2**		Employment Agreement, dated March 19, 2012, by and between Concho Resources Inc. and Steven H. Pruett (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on March 22, 2012 and incorporated herein by reference).

10.3**		Indemnification Agreement, dated March 19, 2012, by and between Concho Resources Inc. and Steven H. Pruett (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K on March 22, 2012 and incorporated herein by reference).

10.4		Eighth Amendment to Amended and Restated Credit Agreement, dated as of April 12, 2012, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 16, 2012, 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.

101.INS (a)		XBRL Instance Document.

101.SCH (a)		XBRL Schema Document.

101.CAL (a)		XBRL Calculation Linkbase Document.

101.DEF (a)		XBRL Definition Linkbase Document.

101.LAB (a)		XBRL Labels Linkbase Document.

101.PRE (a)		XBRL Presentation Linkbase Document.

(a)	Filed herewith.

(b)	Furnished herewith.

**	Management contract or compensatory plan or arrangement.