Concho Resources (CXO) 10-Q 2013 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2013

or

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

For the transition period from to

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)

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

(432) 683-7443

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o 

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

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

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

Number of shares of the registrant’s common stock outstanding at April 29, 2013: 104,731,689 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	42
	Item 3. Quantitative and Qualitative Disclosures About Market Risk	59
	Item 4. Controls and Procedures	61
PART II – OTHER INFORMATION:		62
	Item 1. Legal Proceedings	62
	Item 1A. Risk Factors	62
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	62
	Item 6. Exhibits	63

i

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and 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 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, 2012 and in this report, as well as those factors summarized below:

·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;

·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.   

ii

PART I – FINANCIAL INFORMATION

Item 1.  Consolidated Financial Statements (Unaudited)

Consolidated Balance Sheets at March 31, 2013 and December 31, 2012	1
Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012	2
Consolidated Statement of Stockholders' Equity for the Three Months Ended March 31, 2013	3
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012	4
Condensed Notes to Consolidated Financial Statements	5

iii

Concho Resources Inc.
Consolidated Balance Sheets
Unaudited
					March 31,		December 31,
(in thousands, except share and per share amounts)					2013		2012
Assets
Current assets:
	Cash and cash equivalents			$	974	$	2,880
	Accounts receivable, net of allowance for doubtful accounts:
		Oil and natural gas			195,524		198,053
		Joint operations and other			209,057		202,738
	Derivative instruments				7,201		35,942
	Deferred income taxes				16,420		-
	Prepaid costs and other				17,226		19,269
			Total current assets		446,402		458,882
Property and equipment:
	Oil and natural gas properties, successful efforts method				9,907,856		9,455,599
	Accumulated depletion and depreciation				(1,729,399)		(1,565,316)
		Total oil and natural gas properties, net			8,178,457		7,890,283
	Other property and equipment, net				103,578		103,141
		Total property and equipment, net			8,282,035		7,993,424
Deferred loan costs, net					74,355		77,609
Intangible asset - operating rights, net					29,711		30,076
Inventory					20,604		20,611
Noncurrent derivative instruments					2,908		2,769
Other assets					7,383		6,066
Total assets				$	8,863,398	$	8,589,437
Liabilities and Stockholders’ Equity
Current liabilities:
	Accounts payable:
		Trade		$	7,333	$	31,144
		Related parties			629		185
	Bank overdrafts				39,000		24,275
	Revenue payable				133,389		162,073
	Accrued and prepaid drilling costs				371,976		351,919
	Derivative instruments				34,029		1,584
	Deferred income taxes				-		8,566
	Other current liabilities				183,432		160,340
			Total current liabilities		769,788		740,086
Long-term debt					3,264,626		3,101,103
Deferred income taxes					1,220,440		1,186,621
Noncurrent derivative instruments					16,035		12,049
Asset retirement obligations and other long-term liabilities					87,026		83,382
Commitments and contingencies (Note J)
Stockholders’ equity:
	Common stock, $0.001 par value; 300,000,000 authorized; 104,848,854 and
		104,668,427 shares issued at March 31, 2013 and December 31, 2012, respectively			105		105
	Additional paid-in capital				1,994,817		1,982,714
	Retained earnings				1,520,656		1,490,563
	Treasury stock, at cost; 118,591 and 86,861 shares at March 31, 2013 and December 31,
		2012, respectively			(10,095)		(7,186)
			Total stockholders’ equity		3,505,483		3,466,196
Total liabilities and stockholders’ equity				$	8,863,398	$	8,589,437
The accompanying notes are an integral part of these consolidated financial statements.

1

Concho Resources Inc.
Consolidated Statements of Operations
Unaudited
			Three Months Ended
			March 31,
(in thousands, except per share amounts)				2013		2012
Operating revenues:
	Oil sales		$	393,208	$	383,963
	Natural gas sales			78,919		89,821
		Total operating revenues		472,127		473,784
Operating costs and expenses:
	Oil and natural gas production			100,845		81,577
	Exploration and abandonments			18,407		5,979
	Depreciation, depletion and amortization			168,420		127,263
	Accretion of discount on asset retirement obligations			1,394		841
	General and administrative (including non-cash stock-based compensation of $6,767 and
		$6,128 for the three months ended March 31, 2013 and 2012, respectively)		43,293		27,979
	Loss on derivatives not designated as hedges			59,017		158,093
		Total operating costs and expenses		391,376		401,732
Income from operations				80,751		72,052
Other income (expense):
	Interest expense			(52,106)		(35,837)
	Other, net			(109)		(1,268)
		Total other expense		(52,215)		(37,105)
Income from continuing operations before income taxes				28,536		34,947
	Income tax expense			(10,977)		(13,615)
Income from continuing operations				17,559		21,332
Income from discontinued operations, net of tax				12,534		9,785
Net income			$	30,093	$	31,117
Basic earnings per share:
	Income from continuing operations		$	0.17	$	0.21
	Income from discontinued operations, net of tax			0.12		0.09
		Net income	$	0.29	$	0.30
	Weighted average shares used in basic earnings per share			103,631		102,854
Diluted earnings per share:
	Income from continuing operations		$	0.17	$	0.21
	Income from discontinued operations, net of tax			0.12		0.09
		Net income	$	0.29	$	0.30
	Weighted average shares used in diluted earnings per share			104,345		103,770
The accompanying notes are an integral part of these consolidated financial statements.

2

Concho Resources Inc.
Consolidated Statement of Stockholders’ Equity
Unaudited
							Additional							Total
			Common Stock				Paid-in		Retained	Treasury Stock			Stockholders’
(in thousands)			Shares		Amount		Capital		Earnings	Shares		Amount		Equity
BALANCE AT DECEMBER 31, 2012			104,668	$	105	$	1,982,714	$	1,490,563	87	$	(7,186)	$	3,466,196
	Net income		-		-		-		30,093	-		-		30,093
	Stock options exercised		118		-		2,059		-	-		-		2,059
	Grants of restricted stock		132		-		-		-	-		-		-
	Cancellation of restricted stock		(69)		-		-		-	-		-		-
	Stock-based compensation		-		-		6,767		-	-		-		6,767
	Excess tax benefits related to stock-based
		compensation	-		-		3,277		-	-		-		3,277
	Purchase of treasury stock		-		-		-		-	32		(2,909)		(2,909)
BALANCE AT MARCH 31, 2013			104,849	$	105	$	1,994,817	$	1,520,656	119	$	(10,095)	$	3,505,483
The accompanying notes are an integral part of these consolidated financial statements.

3

Concho Resources Inc.
Consolidated Statements of Cash Flows
Unaudited
					Three Months Ended
					March 31,
(in thousands)					2013		2012
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income				$	30,093	$	31,117
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization				168,420		127,263
		Accretion of discount on asset retirement obligations				1,394		841
		Exploration and abandonments, including dry holes				4,478		3,102
		Non-cash stock-based compensation expense				6,767		6,128
		Deferred income taxes				11,500		12,007
		Loss on sale of assets, net				5		895
		Loss on derivatives not designated as hedges				59,017		158,093
		Discontinued operations				(19,754)		9,315
		Other non-cash items				3,376		2,818
	Changes in operating assets and liabilities, net of acquisitions and dispositions:
			Accounts receivable			12,608		(19,102)
			Prepaid costs and other			726		(1,494)
			Inventory			(21)		6,328
			Accounts payable			(27,679)		(11,727)
			Revenue payable			(15,636)		31,722
			Other current liabilities			(15,623)		(11,401)
				Net cash provided by operating activities		219,671		345,905
CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures on oil and natural gas properties					(419,766)		(541,665)
	Additions to other property and equipment					(4,244)		(20,234)
	Proceeds from the sale of assets					15,865		669
	Funds held in escrow					-		17,394
	Settlements received from (paid on) derivatives not designated as hedges					6,016		(31,911)
				Net cash used in investing activities		(402,129)		(575,747)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from issuance of debt					626,700		1,180,000
	Payments of debt					(463,300)		(978,500)
	Exercise of stock options					2,059		2,996
	Excess tax benefit from stock-based compensation					3,277		6,781
	Payments for loan costs					-		(10,050)
	Purchase of treasury stock					(2,909)		(2,038)
	Bank overdrafts					14,725		30,917
				Net cash provided by financing activities		180,552		230,106
				Net increase (decrease) in cash and cash equivalents		(1,906)		264
Cash and cash equivalents at beginning of period						2,880		342
Cash and cash equivalents at end of period					$	974	$	606
SUPPLEMENTAL CASH FLOWS:
	Cash paid for interest and fees				$	43,988	$	51,647
	Cash paid for income taxes				$	3,145	$	5,455
The accompanying notes are an integral part of these consolidated financial statements.

4

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

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. The Company consolidates the financial statements of these entities. All material intercompany balances and transactions have been eliminated.

Use of estimates in the preparation of financial statements.  Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, 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, 2012 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, 2013 and its results of operations and cash flows for the three months ended March 31, 2013 and 2012. 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 in or omitted from these consolidated financial statements. Accordingly, these consolidated financial statements should be read in conjunction 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, 2012.

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 $74.4 million and $77.6 million, net of accumulated amortization of $42.0 million and $38.8 million, at March 31, 2013 and December 31, 2012, respectively.

5

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Future amortization expense of deferred loan costs at March 31, 2013 was as follows:

(in thousands)
Remaining 2013		$	9,883
2014			13,476
2015			13,842
2016			8,554
2017			5,749
Thereafter			22,851
	Total	$	74,355

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, 2013 and December 31, 2012:

			March 31,		December 31,
(in thousands)			2013		2012
Gross intangible - operating rights		$	36,557	$	36,557
Accumulated amortization			(6,846)		(6,481)
	Net intangible - operating rights	$	29,711	$	30,076

The following table reflects amortization expense from continuing and discontinued operations for the three months ended March 31, 2013 and 2012:

	Three Months Ended
	March 31,
(in thousands)	2013		2012
Amortization expense	$	365	$	387

6

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

The following table reflects the estimated aggregate amortization expense for each of the periods presented below at March 31, 2013:

(in thousands)
Remaining 2013		$	1,096
2014			1,461
2015			1,461
2016			1,461
2017			1,461
Thereafter			22,771
	Total	$	29,711

Oil and natural gas sales and imbalances. Oil and natural gas revenues are recorded at the time of delivery to pipelines for the account of the purchaser or at the time of physical transfer 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 from continuing and discontinued operations totaled approximately $4.2 million and $3.8 million for the three months ended March 31, 2013 and 2012, 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.

7

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

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 adopted this update on January 1, 2013, and the update did not have a significant impact on the consolidated financial statements.

Note C. Exploratory well costs

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are carried in unproved oil and natural gas properties. See Note R for the proved and unproved components of oil and natural gas properties.  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, 2013:

		Three Months Ended
(in thousands)		March 31, 2013
Beginning capitalized exploratory well costs			$	118,806
	Additions to exploratory well costs pending the determination of proved reserves			271,647
	Reclassifications due to determination of proved reserves			(207,400)
	Exploratory well costs charged to expense			(69)
Ending capitalized exploratory well costs			$	182,984

The following table provides an aging at March 31, 2013 and December 31, 2012 of capitalized exploratory well costs based on the date drilling was completed:

			March 31,		December 31,
(in thousands)			2013		2012
Exploratory wells in progress		$	37,605	$	22,837
Capitalized exploratory well costs that have been capitalized for a period of one year or less			145,379		95,969
Capitalized exploratory well costs that have been capitalized for a period greater than one year			-		-
	Total capitalized exploratory well costs	$	182,984	$	118,806

At March 31, 2013, the Company had 104 gross exploratory wells either drilling or waiting on results from completion and testing, of which 42 wells were in the Delaware Basin area, 38 wells were in the New Mexico Shelf area, and 24 wells were in the Texas Permian area.

8

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Note D. Acquisitions 

Three Rivers Acquisition. In July 2012, the Company acquired certain producing and non-producing assets from Three Rivers Operating Company LLC and certain affiliated entities (collectively, the “Three Rivers Acquisition”) for cash consideration of approximately $1.0 billion. The Three Rivers Acquisition was primarily funded with borrowings under the Company’s credit facility. The Company’s results of operations prior to July 2012 do not include results from the Three Rivers Acquisition.

The following table reflects the fair value of the acquired asset and liabilities with the Three Rivers Acquisition:

(in thousands)
Fair value of net assets:
	Proved oil and natural gas properties		$	683,482
	Unproved oil and natural gas properties			359,109
		Total assets acquired		1,042,591
	Current liabilities, including current portion of asset retirement obligations			(2,229)
	Asset retirement obligations assumed			(26,002)
		Fair value of net assets acquired	$	1,014,360
Fair value of consideration paid for net assets:
	Cash consideration		$	1,014,360

9

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

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 $189.2 million.  The PDC Acquisition was primarily funded with borrowings under the Company’s credit facility. The Company’s results of operations prior to March 2012 do not include results from the PDC Acquisition.

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

(in thousands)
Fair value of net assets:
	Current assets		$	2,366
	Proved oil and natural gas properties			159,314
	Unproved oil and natural gas properties			29,687
		Total assets acquired		191,367
	Current liabilities			(123)
	Asset retirement obligations assumed			(2,050)
		Fair value of net assets acquired	$	189,194
Fair value of consideration paid for net assets:
	Cash consideration		$	189,194

Pro forma data. The following unaudited pro forma combined condensed financial data for the three months ended March 31, 2012, were derived from the historical financial statements of the Company giving effect to the Three Rivers Acquisition, as if it had occurred on January 1, 2012. The results of operations since the closing of the Three Rivers Acquisition in July 2012 are included in the Company’s results of operations. The pro forma financial data does not include the results of operations for the PDC Acquisition, as the results of operations were deemed not to be material. The unaudited pro forma combined condensed financial data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Three Rivers Acquisition taken place as of the date indicated and is not intended to be a projection of future results.

		Three Months Ended
(in thousands, except per share amounts)		March 31, 2012
		(unaudited)
Operating revenues		$	510,679
Net income		$	19,333
Earnings per common share:
	Basic	$	0.19
	Diluted	$	0.19

10

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

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, 2013 and 2012 are summarized in the table below:

		Three Months Ended
		March 31,
(in thousands)			2013		2012
Asset retirement obligations, beginning of period		$	86,261	$	59,685
	Liabilities incurred from new wells		1,592		1,777
	Liabilities assumed in acquisitions		161		2,050
	Accretion expense for continuing operations		1,394		841
	Accretion expense for discontinued operations		-		147
	Disposition of wells		(303)		-
	Liabilities settled upon plugging and abandoning wells		(854)		(110)
	Revision of estimates		672		(935)
Asset retirement obligations, end of period		$	88,923	$	63,455

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, 2013 and 2012, were approximately $1.2 million and $0.9 million, respectively.

11

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Stock incentive plan. The Company’s 2006 Stock Incentive Plan, as amended and restated (the “Plan”), provides for granting stock options, restricted stock awards and performance 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, 2013:

		Number of
		Common Shares
Approved and authorized awards		7,500,000
Restricted stock grants, net of forfeitures		(2,044,445)
Stock option grants, net of forfeitures		(3,463,720)
Performance unit grants (a)		(332,667)
Treasury shares		118,591
	Awards available for future grant	1,777,759
(a)	This amount represents the number of units granted (110,889) multiplied by the maximum potential payout of 300 percent.  The actual payout of shares may be between zero percent and 300 percent of the performance units granted depending on the Company's performance at the end of the performance period.

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 award activity for the three months ended March 31, 2013 is presented below:

			Number of		Grant Date
			Restricted		Fair Value
			Shares		Per Share
Restricted stock:
	Outstanding at December 31, 2012		1,072,527
		Shares granted	131,656	$	83.50
		Shares cancelled / forfeited	(69,373)
		Lapse of restrictions	(111,638)
	Outstanding at March 31, 2013		1,023,172

12

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

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, 2013 and 2012:

			Three Months Ended
			March 31,
(in thousands)				2013		2012
Grant date fair value for awards during the period: (a)
	Employee grants		$	593	$	1,254
	Officer and director grants			11,386		17,461
		Total	$	11,979	$	18,715
Stock-based compensation expense from restricted stock:
	Employee grants		$	3,672	$	2,742
	Officer and director grants			2,088		3,277
		Total	$	5,760	$	6,019
Income taxes and other information:
	Income tax benefit related to restricted stock		$	2,202	$	2,301
	Deductions in current taxable income related to restricted stock		$	9,790	$	9,017
(a)		The three months ended March 31, 2013 includes effects of modifications to certain stock-based awards.

Stock option awards.  A summary of the Company’s stock option award activity under the Plan for the three months ended March 31, 2013 is presented below:

					Weighted
					Average
			Number of		Exercise
			Options		Price
Stock options:
	Outstanding at December 31, 2012		429,879	$	20.28
		Options exercised	(118,144)	$	17.43
	Outstanding at March 31, 2013		311,735	$	21.35
	Vested and exercisable at end of period		311,110	$	21.32

13

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

The following table summarizes information about the Company’s vested and exercisable stock options outstanding at March 31, 2013:

			Weighted
			Average	Weighted
	Range of		Remaining	Average
	Exercise	Number	Contractual	Exercise			Intrinsic
	Prices	Vested	Life	Price			Value
							(in thousands)
Vested and exercisable options:
	$8.00	11,597	1.37  years	$	8.00	$	1,037
	$12.00	33,288	2.63  years	$	12.00		2,844
	$12.50 - $15.50	15,000	4.38  years	$	12.85		1,269
	$20.00 - $23.00	192,895	5.29  years	$	21.40		14,667
	$28.00 - $37.27	58,330	5.15  years	$	31.22		3,862
		311,110	4.79  years	$	21.32	$	23,679

The following table summarizes information about stock-based compensation for stock options for the three months ended March 31, 2013 and 2012:

			Three Months Ended
			March 31,
(in thousands)					2013		2012
Stock-based compensation expense from stock options:
	Employee grants			$	1	$	9
	Officer and director grants				13		100
		Total		$	14	$	109
Income taxes and other information:
	Income tax benefit related to stock options			$	5	$	42
	Deductions in current taxable income related to stock options exercised			$	8,501	$	15,016

14

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Performance unit awards. During the three months ended March 31, 2013, the Company awarded performance units to the Company's officers under the Plan. The number of shares of common stock that could be issued will be determined by a combination of (i) comparing the Company's total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. The performance period is 36 months. The grant date fair value was determined using the Monte Carlo simulation method and is being expensed ratably over the performance period.

The Company used the following assumptions to estimate the fair value of performance unit awards granted during the three months ended March 31, 2013:

Risk-free interest rate	0.37%
Range of volatilities	31.5 % - 45.1 %

The following table summarizes the performance unit activity for the three months ended March 31, 2013:

			Number of		Grant Date
			Units (a)		Fair Value
Performance units:
	Outstanding at December 31, 2012		-
		Units granted	110,889	$	111.40
	Outstanding at March 31, 2013		110,889
(a)	Reflects the amount of performance units granted. The actual payout of shares may be between zero and 300 percent of the performance units granted depending on the Company's performance at the end of the performance period.

15

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

The following table summarizes information about the stock-based compensation expense for performance units for the three months ended March 31, 2013:

		Three Months Ended
(in thousands)		March 31, 2013
Stock-based compensation expense from performance units:
	Officer grants	$	993
Income taxes:
	Income tax benefit related to performance units	$	380

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, 2013:

			Restricted		Stock		Performance
(in thousands)			Stock		Options		Units		Total
Remaining 2013		$	21,024	$	1	$	3,088	$	24,113
2014			18,261		-		4,118		22,379
2015			6,630		-		4,154		10,784
2016			1,304		-		-		1,304
2017			10		-		-		10
	Total	$	47,229	$	1	$	11,360	$	58,590

16

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

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 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.

17

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis at March 31, 2013, 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)		2013
	Assets:
		Commodity derivative price swap contracts	$	-	$	28,494	$	-	$	28,494
				-		28,494		-		28,494
	Liabilities:
		Commodity derivative price swap contracts		-		(56,892)		-		(56,892)
		Commodity derivative basis swap contracts		-		(11,557)		-		(11,557)
				-		(68,449)		-		(68,449)
	Net financial liabilities		$	-	$	(39,955)	$	-	$	(39,955)

18

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

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, 2013 and December 31, 2012:

			March 31, 2013				December 31, 2012
			Carrying		Fair		Carrying		Fair
(in thousands)			Value		Value		Value		Value
	Assets:
		Derivative instruments	$	10,109	$	10,109	$	38,711	$	38,711
	Liabilities:
		Derivative instruments	$	50,064	$	50,064	$	13,633	$	13,633
		Credit facility	$	467,400	$	468,247	$	304,000	$	299,679
		8.625% senior notes due 2017	$	297,226	$	318,775	$	297,103	$	323,471
		7.0% senior notes due 2021	$	600,000	$	660,000	$	600,000	$	669,000
		6.5% senior notes due 2022	$	600,000	$	654,000	$	600,000	$	660,000
		5.5% senior notes due 2022	$	600,000	$	624,000	$	600,000	$	633,000
		5.5% senior notes due 2023	$	700,000	$	726,250	$	700,000	$	733,250

19

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Cash and cash equivalents, accounts receivable, other current assets, accountspayable, 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 senior notes are based on quoted market prices.

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, 2013 and December 31, 2012:

					Fair Value Measurements Using
									Significant				Total
					Quoted Prices in				Other		Significant		Fair Value
					Active Markets for				Observable		Unobservable		at
					Identical Assets				Inputs		Inputs		March 31,
(in thousands)					(Level 1)				(Level 2)		(Level 3)		2013
	Assets (a)
		Current:(b)
			Commodity derivative price swap contracts			$	-	$	22,735	$	-	$	22,735
							-		22,735		-		22,735
		Noncurrent:(c)
			Commodity derivative price swap contracts				-		5,759		-		5,759
							-		5,759		-		5,759
	Liabilities (a)
		Current:(b)
			Commodity derivative price swap contracts				-		(38,006)		-		(38,006)
			Commodity derivative basis swap contracts				-		(11,557)		-		(11,557)
							-		(49,563)		-		(49,563)
		Noncurrent:(c)
			Commodity derivative basis swap contracts				-		(18,886)		-		(18,886)
							-		(18,886)		-		(18,886)
	Net financial liabilities					$	-	$	(39,955)	$	-	$	(39,955)
	(b) Total current financial liabilities, gross basis											$	(26,828)
	(c) Total noncurrent financial liabilities, gross basis												(13,127)
				Net financial liabilities								$	(39,955)

20

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

										Fair Value Measurements Using
														Significant								Total
										Quoted Prices in				Other				Significant				Fair Value
										Active Markets for				Observable				Unobservable				at
										Identical Assets				Inputs				Inputs				December 31,
(in thousands)										(Level 1)				(Level 2)				(Level 3)				2012
	Assets (a)
			Current:(b)
				Commodity derivative price swap contracts							$	-	$	56,471			$	-			$	56,471
												-		56,471				-				56,471
			Noncurrent:(c)
				Commodity derivative price swap contracts								-		12,108				-				12,108
												-		12,108				-				12,108
	Liabilities (a)
			Current:(b)
				Commodity derivative price swap contracts								-		(22,113)				-				(22,113)
												-		(22,113)				-				(22,113)
			Noncurrent:(c)
				Commodity derivative price swap contracts								-		(21,388)				-				(21,388)
												-		(21,388)				-				(21,388)
	Net financial assets										$	-	$	25,078			$	-			$	25,078
	(b) Total current financial assets, gross basis																				$	34,358
	(c) Total noncurrent financial liabilities, gross basis																					(9,280)
						Net financial assets															$	25,078
		(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 derivative fair values as reported in the consolidated balance sheets at March 31, 2013 and December 31, 2012:
																March 31,				December 31,
					(in thousands)											2013				2012
					Consolidated Balance Sheets Classification:
							Current derivative contracts:
								Assets							$	7,201			$	35,942
								Liabilities								(34,029)				(1,584)
									Net current						$	(26,828)			$	34,358
							Noncurrent derivative contracts:
								Assets							$	2,908			$	2,769
								Liabilities								(16,035)				(12,049)
									Net noncurrent						$	(13,127)			$	(9,280)

21

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

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 depletion base or by individual well for those wells not constituting part of a depletion 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 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, 2013 or 2012.

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.

22

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

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

		Fair Value Measurements Using
		Quoted Prices				Significant
		in Active				Other		Significant
		Markets for				Observable		Unobservable
		Identical Assets				Inputs		Inputs
(in thousands)		(Level 1)				(Level 2)		(Level 3)
Three Months Ended March 31, 2013
	Asset retirement obligations incurred or assumed		$	-	$	-	$	1,753
Three Months Ended March 31, 2012
	Asset retirement obligations incurred or assumed		$	-	$	-	$	3,827

Note H. Derivative financial instruments

The Company uses derivative financial instruments to manage its exposure to commodity price fluctuations. Commodity derivative instruments 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. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated financial statements.

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.

23

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Commodity derivative contracts at March 31, 2013. The following table sets forth the Company’s outstanding derivative contracts at March 31, 2013. When aggregating multiple contracts, the weighted average contract price is disclosed.

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2013:
		Volume (Bbl)				3,801,000		3,446,000		3,188,000		10,435,000
		Price per Bbl			$	95.84	$	95.57	$	95.34	$	95.60
	2014:
		Volume (Bbl)		2,985,000		2,824,000		2,618,000		2,501,000		10,928,000
		Price per Bbl	$	93.46	$	92.16	$	90.19	$	90.11	$	91.57
	2015:
		Volume (Bbl)		420,000		420,000		119,000		117,000		1,076,000
		Price per Bbl	$	85.91	$	85.91	$	89.44	$	89.43	$	86.69
	2016:
		Volume (Bbl)		108,000		108,000		108,000		105,000		429,000
		Price per Bbl	$	88.32	$	88.32	$	88.32	$	88.28	$	88.31
	2017:
		Volume (Bbl)		84,000		84,000		-		-		168,000
		Price per Bbl	$	87.00	$	87.00	$	-	$	-	$	87.00
Oil Basis Swaps: (b)
	2013:
		Volume (Bbl)				3,458,000		3,220,000		2,944,000		9,622,000
		Price per Bbl			$	(1.19)	$	(1.21)	$	(1.23)	$	(1.21)
(a) The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate monthly average futures price.
(b) The basis differential price is between Midland – WTI and Cushing – WTI.

24

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

The following table summarizes the losses reported in earnings related to the commodity derivative instruments for the three months ended March 31, 2013 and 2012:

					Three Months Ended
					March 31,
(in thousands)						2013		2012
Loss on derivatives not designated as hedges:
	Cash (payments on) receipts from derivatives not designated as hedges:
		Commodity derivatives:
			Oil		$	6,016	$	(32,196)
			Natural gas			-		285
	Mark-to-market loss:
		Commodity derivatives:
			Oil			(65,033)		(126,108)
			Natural gas			-		(74)
				Total loss on derivatives not designated as hedges	$	(59,017)	$	(158,093)

All of the Company’s derivative contracts at March 31, 2013 are expected to settle by June 30, 2017.

Note I. Debt 

The Company’s debt consisted of the following at March 31, 2013 and December 31, 2012:

				March 31,		December 31,
(in thousands)				2013		2012
Credit facility			$	467,400	$	304,000
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		600,000
5.5% unsecured senior notes due 2023				700,000		700,000
Unamortized original issue discount, net				(2,774)		(2,897)
	Less: current portion			-		-
		Total long-term debt	$	3,264,626	$	3,101,103

25

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

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 $3.0 billion until the next scheduled borrowing base redetermination in October 2013, and commitments from the Company’s bank group total $2.5 billion. Between scheduled borrowing base redeterminations, the Company and the lenders (requiring a 66 2/3 percent vote), 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, 2013) or (ii) a Eurodollar rate (substantially equal to the LIBOR). At March 31, 2013, 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, 2013, 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 had their equity pledged to secure borrowings under the Credit Facility.

The Credit Facility 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 last twelve months of 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

·limitations on the payment of cash dividends.

Senior notes. Interest on the Company’s senior notes is paid in arrears semi-annually. The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by all subsidiaries of the Company, subject to customary release provisions as described in Note P.

At March 31, 2013, the Company was in compliance with the covenants under its debt instruments.

26

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Future interest from original issue discount at March 31, 2013 was as follows:

(in thousands)
Remaining 2013		$	385
2014			558
2015			612
2016			672
2017			547
	Total	$	2,774

Principal maturities of debt.Principal maturities of long-term debt outstanding at March 31, 2013 were as follows:

(in thousands)
2013		$	-
2014			-
2015			-
2016			467,400
2017			300,000
Thereafter			2,500,000
	Total	$	3,267,400

27

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Interest expense.  The following amounts have been incurred and charged to interest expense for the three months ended March 31, 2013 and 2012:

		Three Months Ended
		March 31,
(in thousands)			2013		2012
Cash payments for interest		$	43,988	$	51,647
Amortization of original issue discount			123		111
Amortization of deferred loan origination costs			3,254		2,706
Net changes in accruals			4,741		(18,627)
	Total interest expense	$	52,106	$	35,837

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 $5.0 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 regular basis and will establish and adjust any reserves as appropriate to reflect its assessment of the then current status of the matters.

28

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

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, 2013:

	Payments Due By Period
				Less than		1-3		3-5		More than
(in thousands)		Total		1 year		years		years		5 years
Contractual drilling commitments	$	8,943	$	7,495	$	1,448	$	-	$	-

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, 2013 and 2012 were approximately $1.2 million and $1.1 million, respectively.

Future minimum lease commitments under non-cancellable operating leases at March 31, 2013 were as follows:

(in thousands)
Remaining 2013		$	4,030
2014			4,459
2015			3,140
2016			2,270
2017			535
Thereafter			1,689
	Total	$	16,123

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 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, 2013 and December 31, 2012, the Company had current income taxes payable of approximately $5.7 million and $2.1 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

29

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

to their expiration. At March 31, 2013 and December 31, 2012, the Company had no valuation allowances related to its deferred tax assets.

At March 31, 2013, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements.  The tax years 2009 through 2012 remain subject to examination by the major tax jurisdictions.

Income tax provision.  The Company’s income tax provision and amounts separately allocated were attributable to the following items for the three months ended March 31, 2013 and 2012:

		Three Months Ended
		March 31,
(in thousands)			2013		2012
Income from continuing operations		$	10,977	$	13,615
Income from discontinued operations			7,829		5,502
Changes in stockholders' equity:
	Excess tax benefits related to stock-based compensation		(3,277)		(6,781)
		$	15,529	$	12,336

The Company’s income tax provision attributable to income from continuing operations consisted of the following for the three months ended March 31, 2013 and 2012:

				Three Months Ended
				March 31,
(in thousands)					2013		2012
Current:
	U.S. federal			$	(703)	$	768
	U.S. state and local				180		840
		Total current income tax provision (benefit)			(523)		1,608
Deferred:
	U.S. federal				10,253		11,077
	U.S. state and local				1,247		930
		Total deferred income tax provision			11,500		12,007
			Total income tax provision attributable to income from continuing operations	$	10,977	$	13,615

30

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

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

		Three Months Ended
		March 31,
(in thousands)			2013		2012
Income at U.S. federal statutory rate		$	9,988	$	12,231
State income taxes (net of federal tax effect)			928		1,151
Statutory depletion			(13)		(16)
Nondeductible expense & other			74		249
	Income tax expense	$	10,977	$	13,615
Effective tax rate			38.5%		39.0%

The Company’s income tax provision attributable to income from discontinued operations consisted of the following for the three months ended March 31, 2013 and 2012:

				Three Months Ended
				March 31,
(in thousands)				2013		2012
Current:
	U.S. federal			$	6,479	$	4,912
	U.S. state and local				741		28
		Total current income tax provision			7,220		4,940
Deferred:
	U.S. federal				332		(125)
	U.S. state and local				277		687
		Total deferred income tax provision			609		562
			Total income tax provision attributable to income from discontinued operations	$	7,829	$	5,502

31

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Note L. Related party transactions

The following tables summarize charges incurred with and payments made to related parties and reported in the Company’s 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)		2013		2012
Royalty interests paid to a director and certain officers of the Company (a)	$	1,350	$	439
Amounts paid under consulting agreement with Steven L. Beal (b)	$	60	$	60

		March 31,		December 31,
(in thousands)		2013		2012
Amounts included in accounts payable - related parties:
	Royalty interests of a director of the Company (a)	$	629	$	185

(a)Royalties are paid (i) on certain properties to a partnership of which a director is the general partner and owns a 3.5 percent partnership interest (approximately $1.3 million) and (ii) to a director and certain officers who own overriding royalty interests in properties owned by the Company.

(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.

32

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Note M. Discontinued operations

In December 2012, the Company closed the sale of certain of its non-core assets for cash consideration of approximately $503.9 million, which resulted in a final pre-tax gain of approximately $1.7 million. As a result of post-closing adjustments during the three months ended March 31, 2013, the Company made an adjustment to its pre-tax gain of approximately $20.4 million. The Company reflected the results 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, 2013 and 2012:

			Three Months Ended
			March 31,
(in thousands)			2013		2012
Operating revenues:
	Oil sales		$	-	$	29,684
	Natural gas sales			-		4,337
		Total operating revenues		-		34,021
Operating costs and expenses:
	Oil and natural gas production			-		10,573
	Depreciation, depletion and amortization (a)			-		8,606
	Accretion of discount on asset retirement obligations (a)			-		147
	General and administrative (b)			-		(592)
		Total operating costs and expenses		-		18,734
Income from operations				-		15,287
Other income (expense):
	Gain on disposition of assets, net (a)			20,363		-
Income from discontinued operations before income taxes				20,363		15,287
Income tax expense:
	Current			(7,220)		(4,940)
	Deferred (a)			(609)		(562)
Income from discontinued operations, net of tax			$	12,534	$	9,785
(a) Represents the significant non-cash components of discontinued operations.
(b) Represents the fees received from third-parties for operating oil and natural gas properties that were sold. The Company
	reflects these fees as a reduction of general and administrative expenses.

33

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

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, restricted stock and performance units. 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, 2013 and 2012:

			Three Months Ended
			March 31,
(in thousands)			2013	2012
Weighted average common shares outstanding:
	Basic		103,631	102,854
		Dilutive common stock options	204	481
		Dilutive restricted stock	510	435
		Dilutive performance units	-	-
	Diluted		104,345	103,770

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

		Three Months Ended
		March 31,
(in thousands)		2013	2012
Number of antidilutive common shares:
	Antidilutive common stock options	-	-
	Antidilutive restricted stock	13	150
	Antidilutive performance units	111	-

34

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Note O. Other current liabilities

The following table provides the components of the Company’s other current liabilities at March 31, 2013 and December 31, 2012:

				March 31,		December 31,
(in thousands)				2013		2012
Other current liabilities:
	Accrued production costs		$	49,471	$	52,825
	Payroll related matters			25,372		16,365
	Accrued interest			69,045		64,304
	Acquisition and divestiture settlements			27,551		18,100
	Asset retirement obligations			2,326		3,308
	Other			9,667		5,438
		Other current liabilities	$	183,432	$	160,340

35

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Note P.  Subsidiary guarantors

Certain of the Company’s wholly-owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be releasedin certain customary circumstances, including (i) in connection with any sale, exchange or other disposition, whether by merger, consolidation or otherwise, of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Company to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee.

See Note I for a summary of the Company’s senior notes. In accordance with practices accepted by the U.S. Securities and Exchange Commission, 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, 2013 and December 31, 2012, condensed consolidating statements of operations and condensed consolidating statements of cash flows for the three months ended March 31, 2013 and 2012, 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 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.

36

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Condensed Consolidating Balance Sheet
March 31, 2013
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
ASSETS
Accounts receivable - related parties		$	5,974,511	$	1,271,563	$	(7,246,074)	$	-
Other current assets			27,881		418,521		-		446,402
Oil and natural gas properties, net			-		8,178,457		-		8,178,457
Property and equipment, net			-		103,578		-		103,578
Investment in subsidiaries			3,307,119		-		(3,307,119)		-
Other long-term assets			77,263		57,698		-		134,961
	Total assets	$	9,386,774	$	10,029,817	$	(10,553,193)	$	8,863,398
LIABILITIES AND EQUITY
Accounts payable - related parties		$	1,271,563	$	5,975,140	$	(7,246,074)	$	629
Other current liabilities			108,628		660,531		-		769,159
Other long-term liabilities			1,236,474		87,027		-		1,323,501
Long-term debt			3,264,626		-		-		3,264,626
Equity			3,505,483		3,307,119		(3,307,119)		3,505,483
	Total liabilities and equity	$	9,386,774	$	10,029,817	$	(10,553,193)	$	8,863,398

Condensed Consolidating Balance Sheet
December 31, 2012
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
ASSETS
Accounts receivable - related parties		$	5,839,995	$	2,416,697	$	(8,256,692)	$	-
Other current assets			46,737		412,145		-		458,882
Oil and natural gas properties, net			-		7,890,283		-		7,890,283
Property and equipment, net			-		103,141		-		103,141
Investment in subsidiaries			3,146,918		-		(3,146,918)		-
Other long-term assets			80,378		56,753		-		137,131
	Total assets	$	9,114,028	$	10,879,019	$	(11,403,610)	$	8,589,437
LIABILITIES AND EQUITY
Accounts payable - related parties		$	1,271,563	$	6,985,314	$	(8,256,692)	$	185
Other current liabilities			76,496		663,405		-		739,901
Other long-term liabilities			1,198,670		83,382		-		1,282,052
Long-term debt			3,101,103		-		-		3,101,103
Equity			3,466,196		3,146,918		(3,146,918)		3,466,196
	Total liabilities and equity	$	9,114,028	$	10,879,019	$	(11,403,610)	$	8,589,437

37

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2013
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	472,127	$	-	$	472,127
Total operating costs and expenses			(59,196)		(332,180)		-		(391,376)
	Income (loss) from operations		(59,196)		139,947		-		80,751
Interest expense			(52,106)		-		-		(52,106)
Other, net			160,201		(109)		(160,201)		(109)
	Income before income taxes		48,899		139,838		(160,201)		28,536
Income tax expense			(10,977)		-		-		(10,977)
	Income from continuing operations		37,922		139,838		(160,201)		17,559
Income (loss) from discontinued operations, net of tax			(7,829)		20,363		-		12,534
	Net income	$	30,093	$	160,201	$	(160,201)	$	30,093

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2012
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	473,784	$	-	$	473,784
Total operating costs and expenses			(158,338)		(243,394)		-		(401,732)
	Income (loss) from operations		(158,338)		230,390		-		72,052
Interest expense			(35,837)		-		-		(35,837)
Other, net			244,409		(1,269)		(244,408)		(1,268)
	Income before income taxes		50,234		229,121		(244,408)		34,947
Income tax expense			(13,615)		-		-		(13,615)
	Income from continuing operations		36,619		229,121		(244,408)		21,332
Income (loss) from discontinued operations, net of tax			(5,502)		15,287		-		9,785
	Net income	$	31,117	$	244,408	$	(244,408)	$	31,117

38

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2013
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Net cash flows provided by (used in) operating activities		$	(171,843)	$	391,514	$	-	$	219,671
Net cash flows provided by (used in) investing activities			6,016		(408,145)		-		(402,129)
Net cash flows provided by financing activities			165,827		14,725		-		180,552
	Net decrease in cash and cash equivalents		-		(1,906)		-		(1,906)
	Cash and cash equivalents at beginning of period		-		2,880		-		2,880
	Cash and cash equivalents at end of period	$	-	$	974	$	-	$	974

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2012
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		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

39

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Note Q.  Subsequent events

New commodity derivative contracts.After March 31, 2013, the Company entered into the following oil price swaps, oil basis swaps, natural gas price swaps and natural gas collars to hedge additional amounts of its estimated future production:

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2013:
		Volume (Bbl)				390,000		517,000		420,000		1,327,000
		Price per Bbl			$	92.52	$	92.50	$	92.48	$	92.50
	2014:
		Volume (Bbl)		356,000		312,000		347,000		319,000		1,334,000
		Price per Bbl	$	89.37	$	89.37	$	89.37	$	89.37	$	89.37
	2015:
		Volume (Bbl)		2,240,000		-		-		-		2,240,000
		Price per Bbl	$	87.43	$	-	$	-	$	-	$	87.43
Oil Basis Swaps: (b)
	2013:
		Volume (Bbl)				150,000		460,000		460,000		1,070,000
		Price per Bbl			$	(0.45)	$	(0.45)	$	(0.45)	$	(0.45)
	2014:
		Volume (Bbl)		900,000		910,000		-		-		1,810,000
		Price per Bbl	$	(0.50)	$	(0.50)	$	-	$	-	$	(0.50)
Natural Gas Swaps: (c)
	2013:
		Volume (MMBtu)				2,280,000		6,992,000		6,992,000		16,264,000
		Price per MMBtu			$	4.25	$	4.25	$	4.25	$	4.25
Natural Gas Collars: (d)
	2014:
		Volume (MMBtu)		5,400,000		5,460,000		5,520,000		5,520,000		21,900,000
		Price per MMBtu	$	3.85 - 4.40	$	3.85 - 4.40	$	3.85 - 4.40	$	3.85 - 4.40	$	3.85 - 4.40
(a)	The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price.
(b)	The basis differential price is between Midland – WTI and Cushing – WTI.
(c)	The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.
(d)	The index prices for the natural gas collars are based on the El Paso Permian delivery point.

40

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2013

Unaudited

Note R.  Supplementary information

Capitalized costs

			March 31,		December 31,
(in thousands)			2013		2012
Oil and natural gas properties:
	Proved		$	8,774,914	$	8,402,154
	Unproved			1,132,942		1,053,445
	Less: accumulated depletion			(1,729,399)		(1,565,316)
		Net capitalized costs for oil and natural gas properties	$	8,178,457	$	7,890,283

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

			Three Months Ended
			March 31,
(in thousands)			2013		2012
Property acquisition costs:
	Proved		$	1,885	$	160,047
	Unproved			27,896		39,356
Exploration				266,690		184,483
Development				174,722		194,731
	Total costs incurred for oil and natural gas properties		$	471,193	$	578,617
(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)		2013		2012
	Proved property acquisition costs		$	161	$	2,050
	Exploration costs			734		798
	Development costs			1,530		44
		Total asset retirement obligations	$	2,425	$	2,892

41

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 divesture discussed below, many comparisons between periods may be difficult or impossible.

In December 2012, we closed the sale of certain of our non-core assets, a portion of which were acquired in the Three Rivers Acquisition, for cash consideration of approximately $503.9 million, which resulted in a final pre-tax gain of approximately $1.7 million (included in discontinued operations).  For the three months ended March 31, 2012, these assets produced an average of 4,561 Boe per day.

In July 2012, we acquired certain producing and non-producing assets from Three Rivers Operating Company (the “Three Rivers Acquisition”) for cash consideration of approximately $1.0 billion. The Three Rivers Acquisition was primarily funded with borrowings under our credit facility. The results of operations prior to July 2012 do not include results from the Three Rivers Acquisition.

In February 2012, we acquired certain producing and non-producing assets from Petroleum Development Corporation (the “PDC Acquisition”) for cash consideration of approximately $189.2 million. 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.

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 those 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 formation, (ii) Delaware Basin, where we primarily target the Bone Spring formation (which includes the Avalon Shale and the Bone Spring 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 61.2 percent of our 447.2 MMBoe of estimated proved reserves at December 31, 2012 and 61.6 percent of our 7.7 MMBoe of production for the three months ended March 31, 2013. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 91.3 percent of our proved developed producing PV-10 and 81.6 percent of our approximately 5,800 gross wells at December 31, 2012. 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, 2013, as compared to the three months ended March 31, 2012, included the following highlights:

·Net income was $30.1 million ($0.29per diluted share) for the first three months of 2013, as compared to net income of $31.1million ($0.30 per diluted share) during the three months ended March 31, 2012. The decrease in net income was primarily due to:

§$1.7 million decrease in oil and natural gas revenues from continuing operations as a result of a 16 percent decrease in commodity price realizations per Boe (excluding the effects of derivative activities) offset in part by a 19percent increase in production;

§$41.2 million increase in depreciation, depletion and amortization (“DD&A”) expense from continuing operations, primarily due to (i) capitalized costs associated with new wells that were successfully drilled and completed in 2012 and 2013 and (ii) our acquisitions in 2012; 

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§$19.3 million increase in oil and natural gas production costs from continuing operations due in part to increased production, related to our wells successfully drilled and completed in 2012 and 2013 and our acquisitions in 2012, partially offset by a decrease in oil and natural gas revenues that directly decreased our oil and natural gas production taxes; and

§$16.3 million increase in interest expense due to a 47 percent increase in the weighted average debt balance outstanding between the periods primarily related to our acquisitions in 2012 and timing of our capital expenditures, offset in part by a lower weighted average interest rate due to (i) the weighted average debt balance of credit facility borrowings bearing a lower interest rate than our senior notes and (ii) our recent senior note issuances having lower interest rates than historical issuances;

§$15.3 million increase in general and administrative expense due to (a) 2013 including an adjustment to our bonus accrual for services related to 2012 of approximately $5.9 million ($0.76 per Boe) and (b) an increase in the number of employees and related personnel expenses to handle our increased activities, both from (i) increased drilling and exploration activities and (ii) our acquisitions in 2012.

partially offset by:

§$20.4 million pre-tax gain from discontinued operations in 2013 related to the post-closing adjustments to our sale of certain non-core assets in the fourth quarter of 2012; and

§$59.0 million loss on derivatives not designated as hedges for the three months ended March 31, 2013, as compared to a $158.1 million loss on derivatives not designated as hedges during the three months ended March 31, 2012.

·Average daily sales volumes from continuing operations increased by 20 percent from 71,471 Boe per day during the first three months of 2012 to 85,926 Boe per day during the first three months of 2013. The increase is primarily attributable to our successful drilling efforts during 2012 and 2013 and our acquisitions in 2012.

·Net cash provided by operating activities decreased by approximately $126.2 million to $219.7 million for the first three months of 2013, as compared to $345.9 million in the first three months of 2012, primarily due to (i) decreased oil and natural gas revenues, (ii) increases in related oil and natural gas production costs, general and administrative expense and interest expense and (iii) a larger negative variances in working capital changes, which adjust for the timing of receipts and payments of actual cash.

·Long-term debt increased by approximately $0.2billion during the first three months of 2013, primarily as a result of drilling activity in excess of our cash flow.

·At March 31, 2013, availability under our credit facility was approximately $2.0billion. 

Commodity Prices

Our results of operations are heavily influenced by commodity prices. Commodity prices may fluctuate widely in response to (i) relatively minor changes in the supply of and demand for oil, (ii) natural gas and NGLs market uncertainty and (iii) a variety of additional factors that are beyond our control. Factors that may impact future commodity prices, including the price of oil, natural gas and NGLs include:

·economic stimulus initiatives in the United States;

·worldwide and continuing economic struggles in Eurozone nations’ economies;

·political and economic developments in the Middle East;

·demand from Asian and European markets;

·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;

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·technological advances affecting energy consumption and energy supply;

·the effect of energy conservation efforts;

·the price and availability of alternative fuels;

·domestic and foreign governmental regulations and taxation;

·the proximity, capacity, cost and availability of pipelines and other transportation facilities;

·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, 2013.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, oil prices were lower during the comparable periods of 2013 measured against 2012, while natural gas prices were significantly higher. The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three months ended March 31, 2013 and 2012, as well as the high and low NYMEX prices for the same periods:

			Three Months Ended
			March 31,
			2013		2012
Average NYMEX prices:
	Oil (Bbl)		$	94.41	$	102.88
	Natural gas (MMBtu)		$	3.49	$	2.52
High and Low NYMEX prices:
	Oil (Bbl):
		High	$	97.94	$	109.77
		Low	$	90.12	$	96.36
	Natural gas (MMBtu):
		High	$	4.07	$	3.10
		Low	$	3.11	$	2.13

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $97.23 and $86.68 per Bbl and $4.41 and $3.90 per MMBtu, respectively, during the period from March 31, 2013 to April 29, 2013. At April 29, 2013, the NYMEX oil price and NYMEX natural gas price were $94.50 per Bbl and $4.39 per MMBtu, respectively.

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Recent Events

2013 capital budget. In November 2012, we announced our 2013 capital budget of approximately $1.6 billion, which we expect will be substantially funded within our cash flow, based on current commodity prices and capital costs. We take a longer-term view on spending 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 costs, we may reduce our capital spending program to be substantially within our cash flow.

The following table summarizes our 2013 capital budget, which does not include acquisitions other than customary purchase of leasehold acreage:

			2013
			Capital
(in millions)			Budget
Drilling and completion costs:
	New Mexico Shelf	$	285
	Delaware Basin		725
	Texas Permian		342
Facilities and other capital in our core operating areas			123
Acquisition of leasehold acreage			75
Geological and geophysical data			35
	Total	$	1,585

Divestiture.In December 2012, we closed the sale of certain of our non-core assets for cash consideration of approximately $503.9 million, which resulted in a final pre-tax gain of approximately $1.7 million. We used the net proceeds from this divestiture to repay a portion of the borrowings under our credit facility. For the three months ended March 31, 2012, these assets produced an average of 4,561 Boe per day. We estimate that the proved reserves of these assets at closing were approximately 35.3 MMBoe.

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Derivative Financial Instruments

Derivative financial instrument exposure.  At March 31, 2013, the fair value of our financial derivatives was a net liability of $40.0million. All of our counterparties to these financial derivatives are parties or affiliates of 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 or its affiliates.

After March 31, 2013, we entered into the following additional oil price swaps, oil basis swaps, natural gas price swaps and natural gas collars to hedge additional amounts of our estimated future production:

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2013:
		Volume (Bbl)				390,000		517,000		420,000		1,327,000
		Price per Bbl			$	92.52	$	92.50	$	92.48	$	92.50
	2014:
		Volume (Bbl)		356,000		312,000		347,000		319,000		1,334,000
		Price per Bbl	$	89.37	$	89.37	$	89.37	$	89.37	$	89.37
	2015:
		Volume (Bbl)		2,240,000		-		-		-		2,240,000
		Price per Bbl	$	87.43	$	-	$	-	$	-	$	87.43
Oil Basis Swaps: (b)
	2013:
		Volume (Bbl)				150,000		460,000		460,000		1,070,000
		Price per Bbl			$	(0.45)	$	(0.45)	$	(0.45)	$	(0.45)
	2014:
		Volume (Bbl)		900,000		910,000		-		-		1,810,000
		Price per Bbl	$	(0.50)	$	(0.50)	$	-	$	-	$	(0.50)
Natural Gas Swaps: (c)
	2013:
		Volume (MMBtu)				2,280,000		6,992,000		6,992,000		16,264,000
		Price per MMBtu			$	4.25	$	4.25	$	4.25	$	4.25
Natural Gas Collars: (d)
	2014:
		Volume (MMBtu)		5,400,000		5,460,000		5,520,000		5,520,000		21,900,000
		Price per MMBtu	$	3.85 - 4.40	$	3.85 - 4.40	$	3.85 - 4.40	$	3.85 - 4.40	$	3.85 - 4.40
(a)	The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price.
(b)	The basis differential price is between Midland – WTI and Cushing – WTI.
(c)	The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.
(d)	The index prices for the natural gas collars are based on the El Paso Permian delivery point.

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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, 2013 and 2012. 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 Three Rivers Acquisition for periods prior to July 2012 and (ii) the PDC Acquisition for periods prior to March 2012. 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,
				2013		2012
Production and operating data from continuing operations:
	Net production volumes:
		Oil (MBbl)			4,767		3,914
		Natural gas (MMcf)			17,798		15,539
		Total (MBoe)			7,733		6,504
	Average daily production volumes:
		Oil (Bbl)			52,967		43,011
		Natural gas (Mcf)			197,756		170,758
		Total (Boe)			85,926		71,471
	Average prices:
		Oil, without derivatives (Bbl)		$	82.49	$	98.10
		Oil, with derivatives (Bbl) (a)		$	83.75	$	89.87
		Natural gas, without derivatives (Mcf)		$	4.43	$	5.78
		Natural gas, with derivatives (Mcf) (a)		$	4.43	$	5.80
		Total, without derivatives (Boe)		$	61.05	$	72.85
		Total, with derivatives (Boe) (a)		$	61.83	$	67.94
	Operating costs and expenses per Boe:
		Lease operating expenses and workover costs		$	7.74	$	6.58
		Oil and natural gas taxes		$	5.31	$	5.96
		Depreciation, depletion and amortization		$	21.79	$	19.57
		General and administrative		$	5.60	$	4.30
	(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)		2013		2012
		Loss on derivatives not designated as hedges:
			Cash receipts from (payments on) oil derivatives	$	6,016	$	(32,196)
			Cash receipts from natural gas derivatives		-		285
			Unrealized mark-to-market loss on commodity derivatives		(65,033)		(126,182)
			Loss on derivatives not designated as hedges	$	(59,017)	$	(158,093)
		The presentation of average prices with derivatives is a non-GAAP measure as a result of including the cash receipts from (payments on) 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.

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The following table sets forth summary information from our discontinued operations concerning our production and operating data for the three months ended March 31, 2012. The discontinued operations presentation is the result of reclassifying the results of operations from our December 2012 non-core assets 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, 2012
Production and operating data from discontinued operations:
	Net production volumes:
		Oil (MBbl)		300
		Natural gas (MMcf)		690
		Total (MBoe)		415
	Average daily production volumes:
		Oil (MBbl)		3,297
		Natural gas (MMcf)		7,582
		Total (MBoe)		4,561
	Average prices:
		Oil, without derivatives (Bbl)	$	98.95
		Oil, with derivatives (Bbl)	$	98.95
		Natural gas, without derivatives (Mcf)	$	6.29
		Natural gas, with derivatives (Mcf)	$	6.29
		Total, without derivatives (Boe)	$	81.98
		Total, with derivatives (Boe)	$	81.98
	Operating costs and expenses per Boe:
		Lease operating expenses and workover costs	$	18.28
		Oil and natural gas taxes	$	7.20
		Depreciation, depletion and amortization	$	20.73
		General and administrative (a)	$	(1.43)
(a)	Represents the fees received from third-parties for operating oil and natural gas properties that were sold. We reflect these fees as a reduction of general and administrative expense.

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Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

Oil and natural gas revenues.  Revenue from oil and natural gas operations was$472.1 million for the three months ended March 31, 2013, a decrease of$1.7 million (less than 1 percent) from $473.8 million for the three months ended March 31, 2012. This decrease was primarily due to a decrease in the realized oil and natural gas prices offset in part by increased production due to (i) successful drilling efforts during 2012 and 2013, (ii) production from the PDC Acquisition which closed in February 2012 and (iii) production from the Three Rivers Acquisition which closed in July 2012. Specific factors affecting oil and natural gas revenues include the following:

·total oil production was 4,767 MBbl for the three months ended March 31, 2013, an increase of 853 MBbl (22 percent) from 3,914 MBbl for the three months ended March 31, 2012; 

·average realized oil price (excluding the effects of derivative activities) was $82.49 per Bbl during the three months ended March 31, 2013, a decrease of 16 percent from $98.10 per Bbl during the three months ended March 31, 2012. For the three months ended March 31, 2013 and 2012, we realized approximately 87.3 percent and 95.3 percent, respectively, of the average NYMEX oil prices for the respective periods. The deterioration of our realization was primarily related to the basis differential between the Midland WTI and Cushing WTI oil price being over $6 per barrel higher for the three months ended March 31, 2013 than the 2012 comparable period.  The increase in the basis differential, which negatively impacted our price, was due to unplanned events outside of our control effecting the operations of takeaway capacity of oil infrastructure.  Subsequent to March 31, 2013, the basis differential has returned to its generally historical level;

·total natural gas production was 17,798 MMcf for the three months ended March 31, 2013, an increase of 2,259 MMcf (15 percent) from 15,539 MMcf for the three months ended March 31, 2012; and

·average realized natural gas price (excluding the effects of derivative activities) was $4.43 per Mcf during the three months ended March 31, 2013, a decrease of 23 percent from $5.78 per Mcf during the three months ended March 31, 2012. For the three months ended March 31, 2013 and 2012, we realized approximately 126.9 percent and 229.4 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Historically, approximately 65 to 80 percent of our total natural gas revenues were derived from the value of the natural gas liquids, with the remaining portion comingfrom the value of the dry natural gas residue. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues historically, our realized natural gas price (excluding the effects of derivatives) has reflected a price greater than the related NYMEX natural gas price. The deterioration of our realization percentage was primarily related to a combination of (i) a higher average NYMEX natural gas price between comparable periods and (ii) a lower price being received for the value of our natural gas liquids included within our natural gas revenue stream.  We estimate that between the comparable periods the value we received per gallon of natural gas liquids decreased approximately 30 percent, which is primarily the result of an increase in the supply of natural gas liquids from the significant industry drilling in liquid prone areas.

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Production expenses.  The following table provides the components of our total oil and natural gas production costs for the three months ended March 31, 2013 and 2012:

				Three Months Ended March 31,
				2013				2012
					Per				Per
(in thousands, except per unit amounts)			Amount		Boe		Amount		Boe
Lease operating expenses			$	54,173	$	7.01	$	41,048	$	6.31
Taxes:
	Ad valorem			5,775		0.75		2,610		0.40
	Production			35,229		4.56		36,177		5.56
Workover costs				5,668		0.73		1,742		0.27
		Total oil and natural gas production expenses	$	100,845	$	13.05	$	81,577	$	12.54

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 $54.2 million ($7.01 per Boe) for the three months ended March 31, 2013, which was an increase of $13.2 million (32 percent) from $41.0 million ($6.31 per Boe) for the three months ended March 31, 2012. The increase in lease operating expenses was primarily due to (i) our wells successfully drilled and completed in 2012 and 2013, (ii) our acquisitions in 2012 and (iii) 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 cost increases in services, primarily labor related, offset in part by additional production from our wells successfully drilled which were completed in 2012 and 2013 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 2012 and 2013 drilling activity in our Texas Permian area and the Texas properties acquired in the PDC Acquisition and the Three Rivers Acquisition.

Production taxes per unit of production were $4.56 per Boe during the three months ended March 31, 2013, a decrease of 18 percent from $5.56 per Boe during the three months ended March 31, 2012. The decrease was directly related to the decrease in commodity prices. Over the same period, our per Boe prices (excluding the effects of derivatives) decreased 16 percent.

Workover expenses were approximately $5.7 million and $1.7 million for the three months ended March 31, 2013 and 2012, respectively. The 2013 and 2012 expenses related primarily to workovers in the Texas Permian and New Mexico Shelf areas performed to restore production. 

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Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the three months ended March 31, 2013 and 2012:

		Three Months Ended
		March 31,
(in thousands)		2013		2012
Geological and geophysical		$	13,929	$	2,877
Exploratory dry hole costs			91		2,982
Leasehold abandonments and other			4,387		120
	Total exploration and abandonments	$	18,407	$	5,979

Our geological and geophysical expense primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, mostly related to our Delaware Basin and Texas Permian areas.

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

For the three months ended March 31, 2013 and 2012, we recorded approximately $4.4 million and $0.1 million of leasehold abandonments, respectively, which related to non-core prospects in our Delaware Basin area and New Mexico Shelf 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, 2013 and 2012:

		Three Months Ended March 31,
		2013				2012
				Per				Per
(in thousands, except per unit amounts)		Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties		$	164,301	$	21.25	$	124,583	$	19.15
Depreciation of other property and equipment			3,754		0.49		2,315		0.36
Amortization of intangible assets - operating rights			365		0.05		365		0.06
	Total depletion, depreciation and amortization	$	168,420	$	21.79	$	127,263	$	19.57
Oil price used to estimate proved oil reserves at period end		$	89.17			$	94.65
Natural gas price used to estimate proved reserved at period end		$	2.95			$	3.73

Depletion of proved oil and natural gas properties was $164.3 million ($21.25 per Boe) for the three months ended March 31, 2013, an increase of $39.7 million (32 percent) from $124.6 million ($19.15 per Boe) for the three months ended March 31, 2012. The increase in depletion expense was primarily due to (i) capitalized costs associated with new wells that were successfully drilled and completed in 2012 and 2013 and (ii) costs associated with our acquisitions in 2012. The increase in depletion expense per Boe was primarily due to (i) the properties acquired in the Three Rivers Acquisition having a higher rate per Boe than our legacy wells, (ii) drilling deeper, higher cost wells and (iii) the decrease in the oil and natural gas prices between periods utilized to determine proved reserves.

The increase in depreciation expense was primarily associated with our increase in our other property and equipment related to buildings and other items as a result of our increasing work force.

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

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General and administrative expenses.The following table provides components of our general and administrative expenses for the three months ended March 31, 2013 and 2012:

		Three months ended March 31,
		2013				2012
				Per				Per
(in thousands, except per unit amounts)		Amount		Boe		Amount		Boe
General and administrative expenses		$	40,688	$	5.26	$	25,091	$	3.86
Non-cash stock-based compensation			6,767		0.88		6,128		0.94
Less: Third-party operating fee reimbursements			(4,162)		(0.54)		(3,240)		(0.50)
	Total general and administrative expenses	$	43,293	$	5.60	$	27,979	$	4.30

General and administrative expenses were approximately $43.3 million ($5.60 per Boe) for the three months ended March 31, 2013, an increase of $15.3 million (55 percent) from $28.0 million ($4.30 per Boe) for the three months ended March 31, 2012. The increase in general and administrative expenses and non-cash stock-based compensation was primarily due to (a) 2013 including an adjustment to our bonus accrual for services related to 2012 of approximately $5.9 million ($0.76 per Boe) and (b) an increase in the number of employees and related personnel expenses to handle our increased activities, both from (i) increased drilling and exploration activities and (ii) our acquisitions in 2012, offset in part by an approximate $2.3 million ($0.30 per Boe) net benefit to stock-based compensation related to forfeitures and modifications of stock-based awards associated with two of our former officers. The increase in general and administrative expenses per Boe was primarily due to (a) 2013 including an adjustment to our bonus accrual for services related to 2012, noted above, and (b) an increase in the number of employees and related personnel expenses to handle our increased activities, offset in part by (i) increased production from our wells successfully drilled and completed in 2012 and 2013, (ii) additional production associated with our acquisitions in 2012 and (iii) increased third-party operating fee reimbursements.

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 $4.2 million and $3.2 million during the three months ended March 31, 2013 and 2012, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations. The increase in third-party operating fee reimbursements is primarily due to drilling and completing wells in which we own a lower working interest resulting in increased third-party income.

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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, 2013 and 2012:

			Three Months Ended
			March 31,
(in thousands)			2013		2012
Cash payments (receipts):
	Commodity derivatives - oil		$	(6,016)	$	32,196
	Commodity derivatives - natural gas			-		(285)
Mark-to-market loss:
	Commodity derivatives - oil			65,033		126,108
	Commodity derivatives - natural gas			-		74
		Loss on derivatives not designated as hedges	$	59,017	$	158,093

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, 2013 and 2012:

		Three Months Ended
		March 31,
(dollars in thousands)		2013		2012
Interest expense		$	52,106	$	35,837
Weighted average interest rate - credit facility			2.1%		2.2%
Weighted average interest rate - senior notes			6.4%		7.0%
	Total weighted average interest rate		5.8%		5.8%
Weighted average credit facility balance		$	405,476	$	567,544
Weighted average senior notes balance			2,800,000		1,620,000
	Total weighted average debt balance	$	3,205,476	$	2,187,544

The increase in weighted average debt balance for the three months ended March 31, 2013 as compared to the corresponding period in 2012 was due primarily to (i) borrowings associated with our acquisitions in 2012 and (ii) timing of our capital expenditures. The increase in interest expense was due to an overall increase in the weighted average debt balance, offset in part by a lower weighted average interest rate due to (i) the weighted average debt balance of credit facility borrowings bearing a lower interest rate than our senior notes and (ii) our recent senior note issuances having lower interest rates than historical issuances.

Income tax provisions.  We recorded an income tax expense of $11.0 million and $13.6 million for the three months ended March 31, 2013 and 2012, respectively. The effective income tax rates for the three months ended March 31, 2013 and 2012 were 38.5 percent and 39.0 percent, respectively.

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Income from discontinued operations, net of tax.In December 2012, we closed the sale of certain of our non-core assets for cash consideration of approximately $503.9 million, which resulted in a final pre-tax gain of approximately $1.7 million. As a result of post-closing adjustments during the three months ended March 31, 2013, we made an adjustment to our pre-tax gain of approximately $20.4 million. We recognized income from discontinued operations of $12.5 million and $9.8 million for the three months ended March 31, 2013 and 2012, respectively.

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

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Capital Commitments, Capital Resources and Liquidity

Capital commitments.  Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, financing under our credit facility 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, 2013 and 2012 totaled $439.1 million and $378.4 million, respectively. The primary reason for the differences in the costs incurred and cash flow expenditures is the timing of payments. The 2013 expenditures were funded in part from borrowings under our credit facility.

In November 2012, we announced our 2013 capital budget of approximately $1.6 billion, which we expect can be substantially funded within our cash flow, based on current commodity prices and capital costs. As our size and financial flexibility have grown, we take a longer-term view on spending 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 costs, we may reduce our capital spending program to be substantially within our cash flow.

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 capital budgets are 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, 2013 and 2012 totaled approximately $29.8million and $199.4million, respectively. The significant acquisitions of proved properties during the three months ended March 31, 2012 primarily related to the PDC Acquisition. Expenditures for leasehold acreage acquisitions (which are expenditures we generally provide for in our planned capital expenditures) included in the total above were approximately $27.9million and $9.7million for the three months ended March 31, 2013 and 2012, respectively.

Divestitures. In December 2012, we closed the sale of certain of our non-core assets for cash consideration of approximately $503.9 million, which resulted in a final pre-tax gain (included in discontinued operations) of approximately $1.7 million. As a result of post-closing adjustments during the three months ended March 31, 2013, we made an adjustment to our pre-tax gain of approximately $20.4 million. For the three months ended March 31, 2012, these assets produced an average of 4,561 Boe per day. We estimate that the proved reserves of these assets at closing were approximately 35.3 MMBoe. We used the net proceeds from this divestiture to 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, 2012, the material changes in our contractual obligations included a $0.2 billion increase in outstanding long-term debt, a $28.4 million decrease in cash interest expense on debt and a $36.4 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

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and information on changes in the fair value of our open derivative obligations during the three months ended March 31, 2013. 

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

Capital resources.  Our primary sources of liquidity have historically 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 borrowings under our credit facility. We currently believe that our cash flow will substantially meet both our short-term working capital requirements and our current 2013 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 changes in cash and cash equivalents for the three months ended March 31, 2013 and 2012:

		Three Months Ended
		March 31,
(in thousands)		2013		2012
Net cash provided by operating activities		$	219,671	$	345,905
Net cash used in investing activities			(402,129)		(575,747)
Net cash provided by financing activities			180,552		230,106
	Net increase (decrease) in cash and cash equivalents	$	(1,906)	$	264

Cash flow from operating activities. The decrease in operating cash flows during the three months ended March 31, 2013 as compared to 2012 was primarily due to (i) decreased oil and natural gas revenues, (ii) increases in related oil and natural gas production costs, general and administrative expense and interest expense and (iii) negative variances in working capital changes.

Our net cash provided by operating activities includes a reduction of $45.6million and $5.7million for the three months ended March 31, 2013 and 2012, 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, 2013 and 2012, we invested $0.4 billion and $0.5 billion, respectively, for capital expenditures on oil and natural gas properties. Cash flows used in investing activities were lower during the three months ended March 31, 2013 as compared to 2012, in part due to our PDC Acquisition in 2012.

Cash flow from financing 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.

Our credit facility has a maturity date of April 25, 2016. Our borrowing base is $3.0 billion until the next scheduled borrowing base redetermination in October 2013, and commitments from our bank group total $2.5 billion. Between scheduled borrowing base redeterminations, the Company and the lenders (requiring a 66 2/3 percent vote), may each request one special redetermination. At March 31, 2013, our availability to borrow additional funds was approximately $2.0 billion based on bank commitments of $2.5 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, 2013) 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.

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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, 2013, we had $1.0million of cash on hand.

At March 31, 2013, the commitments under our credit facility were $2.5 billion, which provided us with approximately $2.0billion of available borrowing capacity. Upon a redetermination, our $3.0 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 stable 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, 2013 was $6.8billion, consisting of debt of $3.3 billion and stockholders’ equity of $3.5 billion. Our debt to book capitalization was 48percent and 47percent at March 31, 2013 and December 31, 2012, respectively. Our ratio of current assets to current liabilities was 0.58to 1.0 at March 31, 2013 as compared to 0.62 to 1.0 at December 31, 2012.

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, 2013, we received an average of $82.49per barrel of oil and $4.43per Mcf of natural gas before consideration of commodity derivative contracts compared to $98.10per barrel of oil and $5.78per Mcf of natural gas in the three months ended March 31, 2012. 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 until recently, 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. Although we have seen a decrease in commodity prices, the cost trends have not followed proportionally.

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Critical Accounting Policies, Practices and Estimates

Our historical consolidated financial statements and related condensed 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, 2013. 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, 2012, filed with the United States Securities and Exchange Commission (the “SEC”) on February 22, 2013.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2012.

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, 2012, 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.

Commodity price risk. We are exposed to market risk as the prices of our commodities are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of our commodities 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 from the commodity prices at March 31, 2013, would have resulted in a net unrealized loss on our commodity price risk management contracts of approximately $229.5 million. 

At March 31, 2013, we had (i) oil price swaps that settle on a monthly basis covering future oil production from April 1, 2013 through June 30, 2017 and (ii) oil basis swaps covering our basis differential from April 1, 2013 to December 31, 2013. See Note H of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on our commodity derivative instruments. The average NYMEX oil price for the three months ended March 31, 2013, was $94.41 per Bbl. At April 29, 2013, the NYMEX oil price was $94.50 per Bbl.

A decrease in the average forward NYMEX oil price below those at March 31, 2013, would decrease the fair value liability of our commodity derivative contracts from their recorded balance at March 31, 2013. 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 forward NYMEX oil price above that at March 31, 2013, would increase the fair value liability of our commodity derivative contracts from their recorded balance at March 31, 2013. 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.

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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, 2013. During the three months ended March 31, 2013, 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, 2013:

		Commodity Derivative
		Instruments
(in thousands)		Net Assets (Liabilities) (a)
Fair value of contracts outstanding at December 31, 2012			$	25,078
	Changes in fair values (b)			(59,017)
	Contract maturities			(6,016)
Fair value of contracts outstanding at March 31, 2013			$	(39,955)
(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.

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

We had total indebtedness of $467.4 million outstanding under our credit facility at March 31, 2013. The impact of a one percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $4.7 million.

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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, 2013 at the reasonable assurance level.

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

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PART II – OTHER INFORMATION

Item 1.  Legal Proceedings

We are 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 regular 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, 2012, 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 Disclosure 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, 2012.  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

Period		Total number of shares withheld (a)	Average price per share		Total number of shares purchased as part of publicly announced plans	Maximum number of shares that may yet be purchased under the plan
January 1, 2013 - January 31, 2013		4,735	$	83.21	-
February 1, 2013 - February 28, 2013		26,995	$	93.18	-
March 1, 2013 - March 31, 2013		-	$	-	-
(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.

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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	Second Amended and Restated Bylaws of Concho Resources Inc., as amended November 7, 2012 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on November 8, 2012, and incorporated herein by reference).
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).
10.1 ** 10.2	Form of Performance Unit Award Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 4, 2013, and incorporated herein by reference). Eleventh Amendment to Amended and Restated Credit Agreement, dated as of April 15, 2013, 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 17, 2013, 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 agreement

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SIGNATURES

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

CONCHO RESOURCES INC.
Date:	May 2, 2013	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 and Chief Financial Officer
			(Principal Financial and Accounting Officer)

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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	Second Amended and Restated Bylaws of Concho Resources Inc., as amended November 7, 2012 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on November 8, 2012, and incorporated herein by reference).
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).
10.1 ** 10.2	Form of Performance Unit Award Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 4, 2013, and incorporated herein by reference). Eleventh Amendment to Amended and Restated Credit Agreement, dated as of April 15, 2013, 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 17, 2013, 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 agreement