Concho Resources (CXO) 10-Q 2012 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2012

or

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

For the transition period from                    to                    

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)

Delaware	76-0818600
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
550 West Texas Avenue, Suite 100 Midland, Texas	79701
(Address of principal executive offices)	(Zip code)

                             (432) 683-7443                            

(Registrant’s telephone number, including area code)

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

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

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

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

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

Number of shares of the registrant’s common stock outstanding at August 3, 2012: 104,297,042 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	39
Item 3. Quantitative and Qualitative Disclosures About Market Risk	59
Item 4. Controls and Procedures	60
PART II – OTHER INFORMATION	61
Item 1. Legal Proceedings	61
Item 1A. Risk Factors	61
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	61
Item 6. Exhibits	62

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, 2011 and in this report, as well as those factors summarized below:

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

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

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

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

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

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

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

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

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

• risks and liabilities associated with acquired properties or businesses;

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

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

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

• competition in the oil and natural gas industry; and

• uncertainty concerning our assumed or possible future results of operations.

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

ii

PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

Consolidated Balance Sheets at June 30, 2012 and December 31, 2011	1
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2012 and 2011	2
Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2012	3
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011	4
Condensed Notes to Consolidated Financial Statements	5

iii

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited

(in thousands, except share and per share amounts)	June 30, 2012		December 31, 2011
Assets
Current assets:
Cash and cash equivalents	$	710	$	342
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas		167,138		213,921
Joint operations and other		208,353		153,746
Derivative instruments		126,723		1,698
Deferred income taxes		-		28,793
Prepaid costs and other		12,144		12,523
Total current assets		515,068		411,023
Property and equipment:
Oil and natural gas properties, successful efforts method		8,279,969		7,347,460
Accumulated depletion and depreciation		(1,388,180)		(1,116,545)
Total oil and natural gas properties, net		6,891,789		6,230,915
Other property and equipment, net		99,590		59,203
Total property and equipment, net		6,991,379		6,290,118
Funds held in escrow		50,000		17,394
Deferred loan costs, net		72,281		65,641
Intangible asset - operating rights, net		32,651		33,425
Inventory		25,749		19,419
Noncurrent derivative instruments		63,029		7,944
Other assets		8,152		4,612
Total assets	$	7,758,309	$	6,849,576
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	29,361	$	23,341
Related parties		540		11
Bank overdrafts		33,528		39,241
Revenue payable		133,808		146,061
Accrued and prepaid drilling costs		319,601		293,919
Derivative instruments		-		56,218
Deferred income taxes		45,076		-
Other current liabilities		137,171		142,686
Total current liabilities		699,085		701,477
Long-term debt		2,523,366		2,080,141
Deferred income taxes		1,120,593		1,002,295
Noncurrent derivative instruments		-		32,254
Asset retirement obligations and other long-term liabilities		59,700		52,670
Commitments and contingencies (Note J)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 104,386,021 and 103,756,222 shares issued at June 30, 2012 and December 31, 2011, respectively		104		104
Additional paid-in capital		1,952,735		1,925,757
Retained earnings		1,409,288		1,058,874
Treasury stock, at cost; 79,643 and 55,990 shares at June 30, 2012 and December 31, 2011, respectively		(6,562)		(3,996)
Total stockholders’ equity		3,355,565		2,980,739
Total liabilities and stockholders’ equity	$	7,758,309	$	6,849,576

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

1

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands, except per share amounts)	2012		2011		2012		2011
Operating revenues:
Oil sales	$	361,313	$	342,747	$	774,960	$	625,174
Natural gas sales		71,483		103,485		165,641		181,898
Total operating revenues		432,796		446,232		940,601		807,072
Operating costs and expenses:
Oil and natural gas production		87,689		69,577		179,839		133,235
Exploration and abandonments		14,398		400		20,377		1,126
Depreciation, depletion and amortization		141,450		98,881		277,319		189,169
Accretion of discount on asset retirement obligations		1,047		715		2,035		1,419
Impairments of long-lived assets		-		76		-		76
General and administrative (including non-cash stock-based compensation of $7,347 and $4,725 for the three months ended June 30, 2012 and 2011, respectively, and $13,475 and $9,193 for the six months ended June 30, 2012 and 2011, respectively)		31,968		22,618		59,355		44,010
(Gain) loss on derivatives not designated as hedges		(403,050)		(144,882)		(244,957)		88,260
Total operating costs and expenses		(126,498)		47,385		293,968		457,295
Income from operations		559,294		398,847		646,633		349,777
Other income (expense):
Interest expense		(41,899)		(21,660)		(77,736)		(51,320)
Other, net		(535)		(1,735)		(1,803)		(2,087)
Total other expense		(42,434)		(23,395)		(79,539)		(53,407)
Income from continuing operations before income taxes		516,860		375,452		567,094		296,370
Income tax expense		(197,563)		(143,270)		(216,680)		(112,801)
Income from continuing operations		319,297		232,182		350,414		183,569
Income from discontinued operations, net of tax		-		-		-		91,188
Net income	$	319,297	$	232,182	$	350,414	$	274,757
Basic earnings per share:
Income from continuing operations	$	3.10	$	2.26	$	3.40	$	1.79
Income from discontinued operations, net of tax		-		-		-		0.89
Net income	$	3.10	$	2.26	$	3.40	$	2.68
Weighted average shares used in basic earnings per share		103,114		102,569		102,984		102,407
Diluted earnings per share:
Income from continuing operations	$	3.07	$	2.24	$	3.38	$	1.77
Income from discontinued operations, net of tax		-		-		-		0.88
Net income	$	3.07	$	2.24	$	3.38	$	2.65
Weighted average shares used in diluted earnings per share		103,880		103,638		103,825		103,570

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, 2011		103,756	$	104	$	1,925,757	$	1,058,874		56	$	(3,996)	$	2,980,739
Net income		-		-		-		350,414		-		-		350,414
Stock options exercised		193		-		3,110		-		-		-		3,110
Grants of restricted stock		450		-		-		-		-		-		-
Cancellation of restricted stock		(13)		-		-		-		-		-		-
Stock-based compensation		-		-		13,475		-		-		-		13,475
Excess tax benefits related to stock-based compensation		-		-		10,393		-		-		-		10,393
Purchase of treasury stock		-		-		-		-		24		(2,566)		(2,566)
BALANCE AT JUNE 30, 2012		104,386	$	104	$	1,952,735	$	1,409,288		80	$	(6,562)	$	3,355,565

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

3

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited

	Six Months Ended June 30,
(in thousands)	2012		2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	350,414	$	274,757
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		277,319		189,169
Impairments of long-lived assets		-		76
Accretion of discount on asset retirement obligations		2,035		1,419
Exploration and abandonments, including dry holes		11,539		168
Non-cash compensation expense		13,475		9,193
Deferred income taxes		202,559		101,967
Loss on sale of assets, net		68		1,455
(Gain) loss on derivatives not designated as hedges		(244,957)		88,260
Discontinued operations		-		(82,118)
Other non-cash items		5,837		(2,321)
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		7,425		(105,761)
Prepaid costs and other		(3,160)		(3,734)
Inventory		(6,385)		(10,868)
Accounts payable		6,549		(29,488)
Revenue payable		(12,253)		66,164
Other current liabilities		500		(12,491)
Net cash provided by operating activities		610,965		485,847
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and natural gas properties		(949,059)		(677,172)
Additions to other property and equipment		(45,701)		(24,981)
Proceeds from the sale of assets		4,419		196,252
Funds held in escrow		(32,606)		-
Settlements paid on derivatives not designated as hedges		(23,624)		(76,047)
Net cash used in investing activities		(1,046,571)		(581,948)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt		1,776,500		1,645,000
Payments of debt		(1,333,500)		(1,569,000)
Exercise of stock options		3,110		7,140
Excess tax benefit from stock-based compensation		10,393		21,117
Payments for loan costs		(12,250)		(24,466)
Purchase of treasury stock		(2,566)		(1,720)
Bank overdrafts		(5,713)		18,043
Net cash provided by financing activities		435,974		96,114
Net increase in cash and cash equivalents		368		13
Cash and cash equivalents at beginning of period		342		384
Cash and cash equivalents at end of period	$	710	$	397
SUPPLEMENTAL CASH FLOWS:
Cash paid for interest and fees, net of $73 capitalized interest in 2011	$	67,528	$	32,069
Cash paid for income taxes	$	12,982	$	14,322

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

4

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Note A. Organization and nature of operations

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

Note B. Summary of significant accounting policies

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

Discontinued operations.In March 2011, the Company sold its Bakken assets for cash consideration of approximately $195.9 million. In 2011, after completion of the final post-closing adjustments, the Company recognized a pre-tax gain on the sale of assets of approximately $135.9 million; however, through the six months ended June 30, 2011, the Company’s results of operations reflected a pre-tax gain on sale of assets of approximately $142.0 million. The Company has reflected the results of operations of these divested assets as discontinued operations, rather than as a component of continuing operations. See Note M for additional information regarding these divestitures and their discontinued operations.

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

Interim financial statements.The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2011 is derived from audited consolidated financial statements. In the opinion of management, the accompanying consolidated financial statements reflect all adjustments necessary to present fairly the Company’s financial position at June 30, 2012, its results of operations for the three and six months ended June 30, 2012 and 2011, and its cash flows for the six months ended June 30, 2012 and 2011. All such adjustments are of a normal recurring nature. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed or omitted from these consolidated financial statements. Accordingly, these consolidated financial statements should be read with the audited consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

Deferred loan costs. Deferred loan costs are stated at cost, net of amortization, which is computed using the effective interest and straight-line methods. The Company had deferred loan costs of $72.3 million and $65.6 million, net of accumulated amortization of $32.4 million and $26.8 million, at June 30, 2012 and December 31, 2011, respectively.

5

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Future amortization expense of deferred loan costs at June 30, 2012 was as follows:

(in thousands)
Remaining 2012	$	6,046
2013		12,296
2014		12,586
2015		12,899
2016		7,556
Thereafter		20,898
Total	$	72,281

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 June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011
Gross intangible - operating rights	$	38,717	$	38,717
Accumulated amortization		(6,066)		(5,292)
Net intangible - operating rights	$	32,651	$	33,425

The following table reflects amortization expense for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Amortization expense	$	387	$	387	$	774	$	774

6

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

The following table reflects the estimated aggregate amortization expense for each of the periods presented below at June 30, 2012:

(in thousands)
Remaining 2012	$	775
2013		1,549
2014		1,549
2015		1,549
2016		1,549
Thereafter		25,680
Total	$	32,651

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

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

General and administrative expense.The Company receives fees for the operation of jointly owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $4.3 million and $3.1 million for the three months ended June 30, 2012 and 2011, respectively, and $8.1 million and $5.7 million for the six months ended June 30, 2012 and 2011, respectively.

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

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

7

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Note C. Exploratory well costs

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

The following table reflects the Company’s capitalized exploratory well activity during the three and six months ended June 30, 2012:

(in thousands)	Three Months Ended June 30, 2012		Six Months Ended June 30, 2012
Beginning capitalized exploratory well costs	$	96,058	$	107,767
Additions to exploratory well costs pending the determination of proved reserves		53,176		154,921
Reclassifications due to determination of proved reserves		(56,555)		(170,009)
Exploratory well costs charged to expense		-		-
Ending capitalized exploratory well costs	$	92,679	$	92,679

The following table provides an aging at June 30, 2012 and December 31, 2011 of capitalized exploratory well costs based on the date drilling was completed:

(in thousands)	June 30, 2012		December 31, 2011
Exploratory wells in progress	$	18,710	$	24,963
Capitalized exploratory well costs that have been capitalized for a period of one year or less		73,969		82,804
Capitalized exploratory well costs that have been capitalized for a period greater than one year		-		-
Total capitalized exploratory well costs	$	92,679	$	107,767

At June 30, 2012, the Company had 86 gross exploratory wells either drilling or waiting on results from completion, of which 20 wells were in the New Mexico Shelf area, 39 wells were in the Delaware Basin area and 27 wells were in the Texas Permian area.

8

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Note D. Acquisitions and business combinations

PDC Acquisition.In February 2012, the Company acquired certain producing and non-producing assets from Petroleum Development Corporation (the “PDC Acquisition”) for cash consideration of approximately $189.2 million. The PDC Acquisition was primarily funded with borrowings under the Company’s credit facility. The results of operations prior to March 2012 do not include results from the PDC Acquisition.

The following table reflects the estimated 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

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

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

(in thousands)
Fair value of net assets:
Current assets, net of cash acquired of $205	$	5,579
Proved oil and natural gas properties		98,383
Unproved oil and natural gas properties		164,798
Total assets acquired		268,760
Current liabilities		(16,438)
Asset retirement obligations		(321)
Total liabilities assumed		(16,759)
Fair value of net assets acquired	$	252,001
Fair value of consideration paid for net assets:
Cash consideration, net of cash acquired of $205	$	252,001

9

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Note E. Asset retirement obligations

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

The Company’s asset retirement obligation transactions during the three and six months ended June 30, 2012 and 2011 are summarized in the table below:

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Asset retirement obligations, beginning of period	$	63,455	$	43,788	$	59,685	$	43,326
Liabilities incurred from new wells		1,489		1,416		3,266		3,239
Liabilities assumed in acquisitions		77		-		2,127		148
Accretion expense for continuing operations		1,047		715		2,035		1,419
Accretion expense for discontinued operations		-		-		-		8
Disposition of wells		(66)		-		(66)		(412)
Liabilities settled upon plugging and abandoning wells		(132)		(385)		(242)		(686)
Revision of estimates		2,219		(339)		1,284		(1,847)
Asset retirement obligations, end of period	$	68,089	$	45,195	$	68,089	$	45,195

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 June 30, 2012 and 2011, were approximately $1.0 million and $0.5 million, respectively, and approximately $1.9 million and $0.9 million for the six months ended June 30, 2012 and 2011, respectively.

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 June 30, 2012:

	Number of Common Shares
Approved and authorized awards		7,500,000
Stock option grants, net of forfeitures		(3,463,720)
Restricted stock grants, net of forfeitures		(2,006,525)
Treasury shares		79,643
Awards available for future grant		2,109,398

10

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Restricted stock awards.All restricted shares are treated as issued and outstanding in the accompanying consolidated balance sheets. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and cancelled and are no longer considered issued and outstanding. A summary of the Company’s restricted stock awards activity for the six months ended June 30, 2012 is presented below:

	Number of Restricted Shares		Grant Date Fair Value Per Share
Restricted stock:
Outstanding at December 31, 2011		912,013
Shares granted		449,570	$	98.67
Shares cancelled / forfeited		(13,301)
Lapse of restrictions		(210,569)
Outstanding at June 30, 2012		1,137,713

The following table summarizes information about stock-based compensation for the Company’s restricted stock awards activity under the Plan for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2012		2011			2012		2011
Grant date fair value for awards during the period:
Employee grants	$	24,872	$	1,646		$	26,126	$	3,576
Officer and director grants		770		250			18,231		9,050
Total	$	25,642	$	1,896		$	44,357	$	12,626
Stock-based compensation expense from restricted stock:
Employee grants	$	3,021	$	1,809	��	$	5,763	$	3,651
Officer and director grants		4,299		2,707			7,576		4,993
Total	$	7,320	$	4,516		$	13,339	$	8,644
Income taxes and other information:
Income tax benefit related to restricted stock	$	2,798	$	1,727		$	5,099	$	3,305
Deductions in current taxable income related to restricted stock	$	12,521	$	4,934		$	21,538	$	12,012

11

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Stock option awards. A summary of the Company’s stock option awards activity under the Plan for the six months ended June 30, 2012 is presented below:

	Number of Options		Weighted Average Exercise Price
Stock options:
Outstanding at December 31, 2011		930,178	$	18.10
Options exercised		(193,530)	$	16.08
Outstanding at June 30, 2012		736,648	$	18.64
Vested and exercisable at end of period		702,471	$	18.47

The following table summarizes information about the Company’s vested and exercisable stock options outstanding at June 30, 2012:

			Weighted
			Average		Weighted
Range of	Number		Remaining		Average
Exercise	Vested and		Contractual		Exercise		Intrinsic
Prices	Exercisable		Life		Price		Value
							(in thousands)
Vested and exercisable options:
$8.00		104,493		2.12 years	$	8.00	$	8,059
$12.00		45,911		3.34 years	$	12.00		3,357
$12.50 - $15.50		140,000		4.08 years	$	15.13		9,799
$20.00 - $23.00		385,864		5.87 years	$	21.60		24,512
$28.00 - $37.27		60,380		5.93 years	$	31.32		3,249
		736,648		4.85 years	$	18.64	$	48,976

12

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

The following table summarizes information about stock-based compensation for stock options for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Stock-based compensation expense from stock options:
Employee grants	$	8	$	22	$	17	$	45
Officer and director grants		19		187		119		504
Total	$	27	$	209	$	136	$	549
Income taxes and other information:
Income tax benefit related to stock options	$	11	$	80	$	53	$	210
Deductions in current taxable income related to stock options exercised	$	1,072	$	8,914	$	16,088	$	52,155

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 June 30, 2012:

(in thousands)	Restricted Stock		Stock Options		Total
Remaining 2012	$	17,418	$	48	$	17,466
2013		25,855		16		25,871
2014		16,104		-		16,104
2015		4,806		-		4,806
2016 and thereafter		600		-		600
Total	$	64,783	$	64	$	64,847

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

13

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company utilizes its counterparties’ valuations to assess the reasonableness of its prices and valuation techniques.

Level 3:

Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Level 3 instruments primarily include derivative instruments, such as commodity price collars and floors, as well as investments. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although the Company utilizes its counterparties’ valuations to assess the reasonableness of its prices and valuation techniques, the Company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis at June 30, 2012 for each of the fair value hierarchy levels:

	Fair Value Measurements at Reporting Date  Using
			Significant
	Quoted Prices in		Other		Significant
	Active Markets for		Observable		Unobservable		Fair Value at
	Identical Assets		Inputs		Inputs		June 30,
(in thousands)	(Level 1)		(Level 2)		(Level 3)		2012
Assets:
Commodity derivative price swap contracts	$	-	$	206,941	$	-	$	206,941
		-		206,941		-		206,941
Liabilities:
Commodity derivative price swap contracts		-		(17,189)		-		(17,189)
		-		(17,189)		-		(17,189)
Net financial assets	$	-	$	189,752	$	-	$	189,752

14

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table presents the carrying amounts and fair values of the Company’s financial instruments at June 30, 2012 and December 31, 2011:

	June 30, 2012				December 31, 2011
(in thousands)	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets:
Derivative instruments	$	189,752	$	189,752	$	9,642	$	9,642
Liabilities:
Derivative instruments	$	-	$	-	$	88,472	$	88,472
Credit facility	$	426,500	$	403,769	$	583,500	$	532,805
8.625% senior notes due 2017	$	296,866	$	327,295	$	296,641	$	324,080
7.0% senior notes due 2021	$	600,000	$	640,500	$	600,000	$	644,400
6.5% senior notes due 2022	$	600,000	$	622,500	$	600,000	$	627,000
5.5% senior notes due 2022	$	600,000	$	591,000	$	-	$	-

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

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

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

15

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table summarizes (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at June 30, 2012 and December 31, 2011:

	Fair Value Measurements Using
(in thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value at June 30, 2012
Assets(a)
Current:(b)
Commodity derivative price swap contracts	$	-	$	133,868	$	-	$	133,868
		-		133,868		-		133,868
Noncurrent:(c)
Commodity derivative price swap contracts		-		73,073		-		73,073
		-		73,073		-		73,073
Liabilities(a)
Current:(b)
Commodity derivative price swap contracts		-		(7,145)		-		(7,145)
		-		(7,145)		-		(7,145)
Noncurrent:(c)
Commodity derivative price swap contracts		-		(10,044)		-		(10,044)
		-		(10,044)		-		(10,044)
Net financial assets	$	-	$	189,752	$	-	$	189,752
(b) Total current financial assets, gross basis							$	126,723
(c) Total noncurrent financial assets, gross basis								63,029
Net financial assets							$	189,752

16

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

	Fair Value Measurements Using
(in thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value at December 31, 2011
Assets(a)
Current:(b)
Commodity derivative price swap contracts	$	-	$	28,485	$	-	$	28,485
		-		28,485		-		28,485
Noncurrent:(c)
Commodity derivative price swap contracts		-		19,122		-		19,122
		-		19,122		-		19,122
Liabilities(a)
Current:(b)
Commodity derivative price swap contracts		-		(83,005)		-		(83,005)
		-		(83,005)		-		(83,005)
Noncurrent:(c)
Commodity derivative price swap contracts		-		(43,432)		-		(43,432)
		-		(43,432)		-		(43,432)
Net financial liabilities	$	-	$	(78,830)	$	-	$	(78,830)
(b) Total current financial liabilities, gross basis							$	(54,520)
(c) Total noncurrent financial liabilities, gross basis								(24,310)
Net financial liabilities							$	(78,830)

(a) The fair value of derivative instruments reported in the Company’s consolidated balance sheets is subject to netting arrangements and qualifies for net presentation. The following table reports the net basis derivative fair values as reported in the consolidated balance sheets at June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011
Consolidated Balance Sheet Classification:
Current derivative contracts:
Assets	$	126,723	$	1,698
Liabilities		-		(56,218)
Net current	$	126,723	$	(54,520)
Noncurrent derivative contracts:
Assets	$	63,029	$	7,944
Liabilities		-		(32,254)
Net noncurrent	$	63,029	$	(24,310)

17

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

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

The Company periodically reviews its proved oil and natural gas properties that are sensitive to oil and natural gas price fluctuations for impairment. Impairment expense is caused primarily due to declines in commodity prices and well performance. The Company did not recognize any impairment charges for the three or six months ended June 30, 2012. The following table reports the carrying amounts, estimated fair values and impairment expense of long-lived assets for continuing and discontinued operations for the three and six months ended June 30, 2011:

(in thousands)	Carrying Amount		Estimated Fair Value		Impairment Expense
Three Months Ended June 30, 2011	$	77	$	1	$	76
Six Months Ended June 30, 2011	$	77	$	1	$	76

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.

18

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

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

	Fair Value Measurements Using
(in thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Impairment Loss
Three Months Ended June 30, 2012:
Impairment of long-lived assets	$	-	$	-	$	-	$	-
Asset retirement obligations incurred in current period		-		-		1,489
Three Months Ended June 30, 2011:
Impairment of long-lived assets	$	-	$	-	$	1	$	76
Asset retirement obligations incurred in current period		-		-		1,416
Six Months Ended June 30, 2012:
Impairment of long-lived assets	$	-	$	-	$	-	$	-
Asset retirement obligations incurred in current period		-		-		3,266
Six Months Ended June 30, 2011:
Impairment of long-lived assets	$	-	$	-	$	1	$	76
Asset retirement obligations incurred in current period		-		-		3,239

19

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Note H. Derivative financial instruments

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

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

New commodity derivative contracts in the first six months of 2012.During the six months ended June 30, 2012, the Company entered into additional commodity derivative contracts to hedge a portion of its estimated future oil production. The following table summarizes information about these additional commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Aggregate Volume		Index Price(a)		Contract Period
Oil (volumes in Bbls):
Price swap		712,000	$	98.90		02/01/12 - 08/31/12
Price swap		150,000	$	98.90		02/01/12 - 11/30/12
Price swap		990,000	$	99.75		02/01/12 - 12/31/12
Price swap		145,000	$	103.65		05/01/12 - 08/31/12
Price swap		150,000	$	104.40		05/01/12 - 10/31/12
Price swap		1,000,000	$	104.00		05/01/12 - 12/31/12
Price swap		396,000	$	97.65		07/01/12 - 12/31/12
Price swap		183,000	$	98.65		01/01/13 - 03/31/13
Price swap		30,000	$	97.20		01/01/13 - 06/30/13
Price swap		230,000	$	104.30		01/01/13 - 08/31/13
Price swap		180,000	$	103.30		01/01/13 - 09/30/13
Price swap		130,000	$	97.65		01/01/13 - 10/31/13
Price swap		110,000	$	97.40		01/01/13 - 11/30/13
Price swap		3,576,000	$	98.73		01/01/13 - 12/31/13
Price swap		1,350,000	$	95.45		01/01/14 - 03/31/14
Price swap		900,000	$	98.81		01/01/14 - 06/30/14
Price swap		456,000	$	92.50		01/01/14 - 12/31/14
Price swap		450,000	$	98.52		04/01/14 - 06/30/14
Price swap		384,000	$	89.30		01/01/15 - 12/31/15
Price swap		348,000	$	88.00		01/01/16 - 12/31/16
Price swap		168,000	$	87.00		01/01/17 - 06/30/17

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

20

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Commodity derivative contracts at June 30, 2012.The following table sets forth the Company’s outstanding derivative contracts at June 30, 2012. When aggregating multiple contracts, the weighted average contract price is disclosed.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
Oil Swaps:(a)
2012:
Volume (Bbl)						3,876,500		3,539,500		7,416,000
Price per Bbl						$96.39		$96.23		$96.31
2013:
Volume (Bbl)		3,265,000		3,085,000		2,912,000		2,769,000		12,031,000
Price per Bbl		$96.43		$96.31		$95.90		$95.59		$96.08
2014:
Volume (Bbl)		2,256,000		1,353,000		453,000		451,000		4,513,000
Price per Bbl		$94.33		$94.61		$86.55		$86.53		$92.85
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
Natural Gas Swaps:(b)
2012:
Volume (MMBtu)						75,000		75,000		150,000
Price per MMBtu						$  6.54		$  6.54		$  6.54

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

(b) The index prices for the natural gas price swaps and collars are based on the NYMEX—Henry Hub last trading day futures price.

21

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

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

The following table summarizes the gains and losses reported in earnings related to the commodity and interest rate derivative instruments for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Gain (loss) on derivatives not designated as hedges:
Cash (payments on) receipts from derivatives not designated as hedges:
Commodity derivatives:
Oil	$	7,963		$	(48,398	)	$	(24,233	)	$	(80,628	)
Natural gas		324			6,076			609			11,205
Interest rate derivatives		-			(5,429	)		-			(6,624	)
Mark-to-market gain (loss):
Commodity derivatives:
Oil		395,128			192,566			269,020			(8,942	)
Natural gas		(365	)		(4,802	)		(439	)		(9,025	)
Interest rate derivatives		-			4,869			-			5,754
Total gain (loss) on derivatives not designated as hedges	$	403,050		$	144,882		$	244,957		$	(88,260	)

All of the Company’s derivative contracts at June 30, 2012 are expected to settle by June 30, 2017.

Note I. Debt

The Company’s debt consisted of the following at June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011
Credit facility	$	426,500	$	583,500
8.625% unsecured senior notes due 2017		300,000		300,000
7.0% unsecured senior notes due 2021		600,000		600,000
6.5% unsecured senior notes due 2022		600,000		600,000
5.5% unsecured senior notes due 2022		600,000		-
Unamortized original issue discount, net		(3,134)		(3,359)
Less: current portion		-		-
Total long-term debt	$	2,523,366	$	2,080,141

22

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Credit facility.In May 2012, the Company amended its credit facility (the “Credit Facility”), increasing the aggregate lender commitments from $2.0 billion to $2.5 billion, equal to its $2.5 billion borrowing base. The next scheduled borrowing base redetermination is in October 2012. Between scheduled borrowing base redeterminations, the Company and the lenders (requiring a 66 2/3 percent vote), may each request one special redetermination. The Company’s Credit Facility has a maturity date of April 25, 2016.

Advances on the Credit Facility bear interest, at the Company’s option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) (3.25 percent at June 30, 2012) or (ii) a Eurodollar rate (substantially equal to the LIBOR). At June 30, 2012, the interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest margins ranging from 150 to 250 basis points and 50 to 150 basis points per annum, respectively, depending on the debt balance outstanding. At June 30, 2012, the Company paid commitment fees on the unused portion of the available commitments ranging from 37.5 to 50 basis points per annum.

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

The Company’s obligations under the Credit Facility are secured by a first lien on substantially all of its oil and natural gas properties. In addition, all of the Company’s subsidiaries are guarantors and have 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 consolidated earnings before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and other noncash income and expenses to be no greater than 4.0 to 1.0, and (ii) maintenance of a ratio of current assets to current liabilities, excluding noncash assets and liabilities related to financial derivatives and asset retirement obligations and including the unfunded amounts under the Credit Facility, to be not less than 1.0 to 1.0;

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

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

• restrictions on the payment of cash dividends.

At June 30, 2012, the Company was in compliance with all of the covenants under the Credit Facility.

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

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

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

23

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

5.5% senior notes.In March 2012, the Company issued $600 million aggregate principal amount of 5.5% senior notes due 2022 at par (the “5.5% 2022 Senior Notes”). The 5.5% 2022 Senior Notes mature on October 1, 2022, and interest is paid in arrears semi-annually on October 1 and April 1, beginning on October 1, 2012. The 5.5% 2022 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries.

Future interest expense from the 2017 Senior Notes original issue discount at June 30, 2012 was as follows:

(in thousands)
Remaining 2012	$	237
2013		507
2014		557
2015		612
2016		672
Thereafter		549
Total	$	3,134

Principal maturities of debt. Principal maturities of long-term debt outstanding at June 30, 2012 were as follows:

(in thousands)
2012	$	-
2013		-
2014		-
2015		-
2016		426,500
Thereafter		2,100,000
Total	$	2,526,500

24

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Interest expense. The following amounts have been incurred and charged to interest expense for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Cash payments for interest	$	15,881	$	21,747	$	67,528	$	32,142
Amortization of original issue discount (premium)		114		32		225		(82)
Amortization of deferred loan origination costs		2,904		2,810		5,610		6,353
Write-off of deferred loan origination costs and original issue premium		-		(8,513)		-		(8,513)
Net changes in accruals		23,000		5,584		4,373		21,493
Interest costs incurred		41,899		21,660		77,736		51,393
Less: capitalized interest		-		-		-		(73)
Total interest expense	$	41,899	$	21,660	$	77,736	$	51,320

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 $5.1 million.

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

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

Contractual drilling commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future, including agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments in the periods in which well capital is incurred or rig services are provided. The following table summarizes the Company’s future drilling commitments at June 30, 2012:

	Payments Due By Period
(in thousands)	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than         5 years
Contractual drilling commitments	$	20,618	$	16,906	$	3,712	$	-	$	-

25

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Operating leases. The Company leases vehicles, equipment and office facilities under non-cancellable operating leases. Lease payments associated with these operating leases for each of the three months ended June 30, 2012 and 2011 were approximately $1.2 million, and approximately $2.3 million and $1.7 million for the six months ended June 30, 2012 and 2011, respectively.

Future minimum lease commitments under non-cancellable operating leases at June 30, 2012 were as follows:

(in thousands)
Remaining 2012	$	2,648
2013		4,059
2014		3,109
2015		2,259
2016		1,570
Thereafter		442
Total	$	14,087

Note K. Income taxes

The Company uses an asset and liability approach for financial accounting and reporting for income taxes. The Company’s objectives of accounting for income taxes are to recognize (i) the amount of taxes payable or refundable for the current year and (ii) deferred tax liabilities and assets for the future tax consequences of events that have been recognized in its financial statements or tax returns. The Company and its subsidiaries file a federal corporate income tax return on a consolidated basis. The tax returns and the amount of taxable income or loss are subject to examination by federal and state taxing authorities. At June 30, 2012 and December 31, 2011, the Company had current income taxes receivable of approximately $2.4 million and $3.9 million, respectively, and current income taxes payable of approximately $0.4 million and $0.8 million, respectively.

The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net operating loss carryforwards (“NOLs”), if any, and other deferred tax attributes in the United States, state, and local tax jurisdictions will be utilized prior to their expiration. At June 30, 2012 and December 31, 2011, the Company had no valuation allowances related to its deferred tax assets.

At June 30, 2012, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2009 through 2011 remain subject to examination by the major tax jurisdictions.

26

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Income tax provision.The Company’s income tax provision and amounts separately allocated were attributable to the following items for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Income from continuing operations	$	197,563	$	143,270	$	216,680	$	112,801
Income from discontinued operations		-		-		-		56,529
Changes in stockholders’ equity:
Excess tax benefits related to stock-based compensation		(3,612)		(4,074)		(10,393)		(21,117)
	$	193,951	$	139,196	$	206,287	$	148,213

The Company’s income tax provision attributable to income from continuing operations consisted of the following for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Current:
U.S. federal	$	6,562	$	3,208	$	12,244	$	9,552
U.S. state and local		1,011		519		1,877		1,282
Total current income tax provision		7,573		3,727		14,121		10,834
Deferred:
U.S. federal		165,317		121,452		176,266		88,599
U.S. state and local		24,673		18,091		26,293		13,368
Total deferred income tax provision		189,990		139,543		202,559		101,967
Total income tax provision attributable to income from continuing operations	$	197,563	$	143,270	$	216,680	$	112,801

27

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

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 June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Income at U.S. federal statutory rate	$	180,901	$	131,409	$	198,483	$	103,730
State income taxes (net of federal tax effect)		16,695		12,097		18,311		9,523
Statutory depletion		(100)		(144)		(116)		(186)
Nondeductible expense & other		67		(92)		2		(266)
Income tax expense	$	197,563	$	143,270	$	216,680	$	112,801
Effective tax rate		38.2%		38.2%		38.2%		38.1%

The Company’s income tax provision attributable to income from discontinued operations consisted of the following for the six months ended June 30, 2011:

(in thousands)	Six Months Ended June 30, 2011
Current:
U.S. federal	$	(1,192)
U.S. state and local		4
Total current income tax benefit		(1,188)
Deferred:
U.S. federal		50,373
U.S. state and local		7,344
Total deferred income tax provision		57,717
Total income tax provision attributable to income from discontinued operations	$	56,529

28

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Note L.Related party transactions

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Royalty interests paid to a director of the Company(a)	$	856	$	33	$	1,295	$	62
Amounts paid under consulting agreement with Steven L. Beal (b)	$	60	$	60	$	120	$	120

(in thousands)	June 30, 2012		December 31, 2011
Amounts included in accounts payable - related parties:
Royalty interests of a director of the Company(a)	$	540	$	11

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

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

29

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Note M.Discontinued operations

In March 2011, the Company sold its Bakken assets for cash consideration of approximately $195.9 million. In 2011, after completion of the final post-closing adjustments, the Company recognized a pre-tax gain on the sale of assets of approximately $135.9 million; however, through the six months ended June 30, 2011, the Company’s results of operations reflected a pre-tax gain on sale of assets of approximately $142.0 million.

The Company reflected the result of operations of this divestiture as discontinued operations, rather than as a component of continuing operations. The following table represents the components of the Company’s discontinued operations for the six months ended June 30, 2011:

(in thousands)	Six Months Ended June 30, 2011
Operating revenues:
Oil sales	$	9,456
Natural gas sales		68
Total operating revenues		9,524
Operating costs and expenses:
Oil and natural gas production		1,642
Depreciation, depletion and amortization(a)		2,107
Accretion of discount on asset retirement obligations(a)		8
Total operating costs and expenses		3,757
Income from operations		5,767
Other income (expense):
Gain on disposition of assets, net(a)		141,950
Income from discontinued operations before income taxes		147,717
Income tax benefit (expense):
Current		1,188
Deferred(a)		(57,717)
Income from discontinued operations, net of tax	$	91,188

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

30

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Note N.Net income per share

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

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

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Weighted average common shares outstanding:
Basic		103,114		102,569		102,984		102,407
Dilutive common stock options		392		575		437		656
Dilutive restricted stock		374		494		404		507
Diluted		103,880		103,638		103,825		103,570

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

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Number of antidilutive common shares:
Antidilutive common stock options		-		-		-		-
Antidilutive restricted stock		196		47		173		25

31

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Note O.Other current liabilities

The following table provides the components of the Company’s other current liabilities at June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012		December 31, 2011
Other current liabilities:
Accrued production costs	$	46,035	$	47,437
Payroll related matters		8,322		18,433
Accrued interest		57,106		52,733
Asset retirement obligations		8,816		7,445
Other		16,892		16,638
Other current liabilities	$	137,171	$	142,686

Note P.Subsidiary guarantors

All of the Company’s wholly-owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. See Note I for a summary of the Company’s senior notes. In accordance with practices accepted by the United States 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 June 30, 2012 and December 31, 2011, Condensed Consolidating Statements of Operations for the three and six months ended June 30, 2012 and 2011, and Condensed Consolidating Statements of Cash Flows for the six months ended June 30, 2012 and 2011, present financial information for Concho Resources Inc. as the Parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors are not restricted from making distributions to the Company.

32

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Condensed Consolidating Balance Sheet June 30, 2012
(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
ASSETS
Accounts receivable - related parties	$	4,241,459	$	214,464	$	(4,455,923)	$	-
Other current assets		145,257		369,811		-		515,068
Oil and natural gas properties, net		-		6,891,789		-		6,891,789
Property and equipment, net		-		99,590		-		99,590
Investment in subsidiaries		2,794,483		-		(2,794,483)		-
Other long-term assets		135,310		116,552		-		251,862
Total assets	$	7,316,509	$	7,692,206	$	(7,250,406)	$	7,758,309
LIABILITIES AND EQUITY
Accounts payable - related parties	$	214,464	$	4,241,999	$	(4,455,923)	$	540
Other current liabilities		102,522		596,023		-		698,545
Other long-term liabilities		1,120,592		59,701		-		1,180,293
Long-term debt		2,523,366		-		-		2,523,366
Equity		3,355,565		2,794,483		(2,794,483)		3,355,565
Total liabilities and equity	$	7,316,509	$	7,692,206	$	(7,250,406)	$	7,758,309

Condensed Consolidating Balance Sheet December 31, 2011
(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
ASSETS
Accounts receivable - related parties	$	4,983,923	$	706,905	$	(5,690,828)	$	-
Other current assets		34,229		376,794		-		411,023
Oil and natural gas properties, net		-		6,230,915		-		6,230,915
Property and equipment, net		-		59,203		-		59,203
Investment in subsidiaries		2,394,050		-		(2,394,050)		-
Other long-term assets		73,587		74,848		-		148,435
Total assets	$	7,485,789	$	7,448,665	$	(8,084,878)	$	6,849,576
LIABILITIES AND EQUITY
Accounts payable - related parties	$	1,271,524	$	4,419,315	$	(5,690,828)	$	11
Other current liabilities		118,836		582,630		-		701,466
Other long-term liabilities		1,034,549		52,670		-		1,087,219
Long-term debt		2,080,141		-		-		2,080,141
Equity		2,980,739		2,394,050		(2,394,050)		2,980,739
Total liabilities and equity	$	7,485,789	$	7,448,665	$	(8,084,878)	$	6,849,576

33

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Condensed Consolidating Statement of Operations Three Months Ended June 30, 2012
(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
Total operating revenues	$	-	$	432,796	$	-	$	432,796
Total operating costs and expenses		402,751		(276,253)		-		126,498
Income from operations		402,751		156,543		-		559,294
Interest expense		(41,899)		-		-		(41,899)
Other, net		156,008		(518)		(156,025)		(535)
Income before income taxes		516,860		156,025		(156,025)		516,860
Income tax expense		(197,563)		-		-		(197,563)
Net income	$	319,297	$	156,025	$	(156,025)	$	319,297

Condensed Consolidating Statement of Operations Three Months Ended June 30, 2011
(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
Total operating revenues	$	-	$	446,232	$	-	$	446,232
Total operating costs and expenses		143,175		(190,560)		-		(47,385)
Income from operations		143,175		255,672		-		398,847
Interest expense		(21,660)		-		-		(21,660)
Other, net		253,937		(1,635)		(254,037)		(1,735)
Income before income taxes		375,452		254,037		(254,037)		375,452
Income tax expense		(143,270)		-		-		(143,270)
Net income	$	232,182	$	254,037	$	(254,037)	$	232,182

34

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2012

(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
Total operating revenues	$	-	$	940,601	$	-	$	940,601
Total operating costs and expenses		244,413		(538,381)		-		(293,968)
Income from operations		244,413		402,220		-		646,633
Interest expense		(77,736)		-		-		(77,736)
Other, net		400,417		(1,787)		(400,433)		(1,803)
Income before income taxes		567,094		400,433		(400,433)		567,094
Income tax expense		(216,680)		-		-		(216,680)
Net income	$	350,414	$	400,433	$	(400,433)	$	350,414

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2011

(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
Total operating revenues	$	-	$	807,072	$	-	$	807,072
Total operating costs and expenses		(87,688)		(369,607)		-		(457,295)
Income (loss) from continuing operations		(87,688)		437,465		-		349,777
Interest expense		(51,320)		-		-		(51,320)
Other, net		583,095		(2,187)		(582,995)		(2,087)
Income from continuing operations before income taxes		444,087		435,278		(582,995)		296,370
Income tax expense		(112,801)		-		-		(112,801)
Income from continuing operations		331,286		435,278		(582,995)		183,569
Income from discontinued operations, net of tax		(56,529)		147,717		-		91,188
Net income	$	274,757	$	582,995	$	(582,995)	$	274,757

35

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Condensed Consolidating Statement of Cash Flows Six Months Ended June 30, 2012
(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
Net cash flows provided by (used in) operating activities	$	(418,065)	$	1,029,030	$	-	$	610,965
Net cash flows used in investing activities		(23,624)		(1,022,947)		-		(1,046,571)
Net cash flows provided by (used in) financing activities		441,689		(5,715)		-		435,974
Net increase in cash and cash equivalents		-		368		-		368
Cash and cash equivalents at beginning of period		-		342		-		342
Cash and cash equivalents at end of period	$	-	$	710	$	-	$	710

Condensed Consolidating Statement of Cash Flows Six Months Ended June 30, 2011
(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
Net cash flows provided by (used in) operating activities	$	(4,955)	$	490,802	$	-	$	485,847
Net cash flows used in investing activities		(72,787)		(509,161)		-		(581,948)
Net cash flows provided by financing activities		78,071		18,043		-		96,114
Net increase (decrease) in cash and cash equivalents		329		(316)		-		13
Cash and cash equivalents at beginning of period		46		338		-		384
Cash and cash equivalents at end of period	$	375	$	22	$	-	$	397

36

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Note Q.Subsequent events

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

	Aggregate Volume		Index Price (a)		Contract Period
Oil (volumes in Bbls):
Price swap		305,000	$	90.45	08/01/2012 - 12/31/2012
Price swap		80,000	$	91.40	01/01/2013 - 04/30/2013
Price swap		44,000	$	91.35	01/01/2013 - 11/30/2013
Price swap		60,000	$	91.45	01/01/2013 - 12/31/2013
Price swap		720,000	$	89.59	01/01/2014 - 06/30/2014
Price swap		810,000	$	89.30	04/01/2014 - 06/30/2014

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

Three Rivers acquisition.In July 2012, the Company acquired substantially all the oil and natural gas assets of Three Rivers Operating Company and certain affiliated entities (collectively, the “Three Rivers Acquisition”) for approximately $1.0 billion in cash, subject to customary post-closing adjustments. The Three Rivers Acquisition was funded with borrowings under the Credit Facility. At June 30, 2012, the Company had paid a $50 million performance guaranty deposit (held in escrow), which was applied to the funding of the purchase at closing.

The results of operations of the Company for the three and six months ended June 30, 2012 do not include results from the Three Rivers Acquisition. The Company is currently evaluating the initial accounting for the business combination and, as such, has not included supplemental pro forma information in this filing.

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2012

Unaudited

Note R.Supplementary information

Capitalized costs

(in thousands)	June 30, 2012		December 31, 2011
Oil and natural gas properties:
Proved	$	7,480,578	$	6,551,396
Unproved		799,391		796,064
Less: accumulated depletion		(1,388,180)		(1,116,545)
Net capitalized costs for oil and natural gas properties	$	6,891,789	$	6,230,915

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

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Property acquisition costs:
Proved	$	5,568	$	3,230	$	165,615	$	69,148
Unproved		21,851		18,132		61,207		75,340
Exploration		159,013		181,353		343,496		271,919
Development		192,051		140,768		386,782		334,485
Total costs incurred for oil and natural gas properties	$	378,483	$	343,483	$	957,100	$	750,892

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

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Proved property acquisition costs	$	77	$	-	$	2,127	$	148
Exploration costs		469		320		1,267		640
Development costs		3,239		757		3,283		752
Total	$	3,785	$	1,077	$	6,677	$	1,540

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

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated financial statements and notes. As a result of the acquisitions and divestures discussed below, many comparisons between periods will be difficult or impossible.

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

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

In March 2011, we sold our Bakken assets for cash consideration of approximately $195.9 million. In 2011, after completion of the final post-closing adjustments, we recognized a pre-tax gain on the sale of assets of approximately $135.9 million; however, through the six months ended June 30, 2011, our results of operations reflected a pre-tax gain on sale of assets of approximately $142.0 million. We have reflected the results of operations of these divested assets as discontinued operations, rather than as a component of continuing operations. See Note M of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding these divestitures and their discontinued operations. For the first quarter of 2011, these assets produced an average of 1,369 Boe per day.

Certain statements in our discussion below are forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause actual results to differ materially from 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 and Lower Abo formations, (ii) Delaware Basin, where we primarily target the Bone Spring formation (which includes the Avalon Shale and the Bone Springs sands) and the Wolfcamp shale, and (iii) Texas Permian, where we primarily target the Wolfberry, a term applied to the combined Wolfcamp and Spraberry horizons. Oil comprised 61.7 percent of our 386.5 MMBoe of estimated proved reserves at December 31, 2011 and 61.4 percent of our 13.7 MMBoe of production for the six months ended June 30, 2012. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 93.0 percent of our proved developed producing PV-10 and 78.8 percent of our 5,504 gross wells at December 31, 2011. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and stimulation methods used.

Financial and Operating Performance

Our financial and operating performance for the six months ended June 30, 2012, as compared to the six months ended June 30, 2011, included the following highlights:

• Net income was $350.4 million ($3.38 per diluted share) for the first six months of 2012, as compared to net income of $274.8 million ($2.65 per diluted share) during the six months ended June 30, 2011. The increase in earnings is primarily due to:

¡ $133.5 million increase in oil and natural gas revenues as a result of a 29 percent increase in production offset by a 9 percent decrease in commodity price realizations per Boe (excluding the effects of derivative activities); and

¡ a $245.0 million gain on derivatives not designated as hedges for the first six months of 2012, as compared to a $88.3 million loss on derivatives not designated as hedges during the six months ended June 30, 2011;

partially offset by:

¡ $142.0 million pre-tax gain from discontinued operations related to the sale of our Bakken assets in the first quarter of 2011;

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¡ $88.2 million increase in depreciation, depletion and amortization (“DD&A”) expense, primarily due to increased production in 2012;

¡ $46.6 million increase in oil and natural gas production costs due in part to increased (i) production, (ii) labor costs, (iii) salt water disposal costs, well service and repair costs, and (iv) oil and natural gas revenues that directly increased our oil and natural gas production taxes; and

¡ $26.4 million increase in interest expense due to (i) a 34 percent increase in the weighted average debt balance outstanding between the periods primarily related to acquisitions, (ii) the May 2011 $600 million issuance of our 6.5% senior notes due 2022, (iii) the March 2012 $600 million issuance of our 5.5% senior notes due 2022 and (iv) the amortization of capitalized loan costs associated with our senior notes; partially offset by the repayment of a $150 million 8.0% senior note in May 2011.

• Average daily sales volumes from continuing operations increased by 28 percent from 58,995 Boe per day during the first half of 2011 to 75,506 Boe per day during the first half of 2012. The increase is primarily attributable to our successful drilling efforts during 2011 and 2012 and our OGX and PDC Acquisitions.

• Net cash provided by operating activities increased by approximately $125.2 million to $611.0 million for the first half of 2012, as compared to $485.8 million in the first half of 2011, primarily due to (i) increased oil and natural gas revenues and (ii) positive variances in working capital changes, offset by increases in related oil and natural gas production costs and other cash related costs.

• Long-term debt increased by approximately $443.2 million during the first half of 2012, primarily as a result of (i) the PDC Acquisition in February 2012, (ii) capital expenditures and (iii) the $50 million deposit related to the Three Rivers Acquisition.

• At June 30, 2012 our availability under our credit facility was approximately $2.1 billion. Pro forma for the closing of the Three Rivers Acquisition, at June 30, 2012, our availability under our credit facility would have been approximately $1.1 billion.

Commodity Prices

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

• developments generally impacting the Middle East;

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

• the overall global demand for oil; and

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

¡ the United States economy impact,

¡ weather conditions, and

¡ liquefied natural gas deliveries to the United States.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Note H of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commodity derivative positions at June 30, 2012.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, oil prices were moderately lower during the comparable periods of 2012 measured against 2011, while natural gas prices were significantly lower.

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The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three and six months ended June 30, 2012 and 2011, as well as the high and low NYMEX prices for the same periods:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Average NYMEX prices:
Oil (Bbl)	$	93.49	$	102.58	$	98.19	$	98.44
Natural gas (MMBtu)	$	2.35	$	4.38	$	2.44	$	4.29
High and Low NYMEX prices:
Oil (Bbl):
High	$	106.16	$	113.93	$	109.77	$	113.93
Low	$	77.69	$	90.61	$	77.69	$	84.32
Natural gas (MMBtu):
High	$	2.82	$	4.85	$	3.10	$	4.85
Low	$	1.91	$	4.04	$	1.91	$	3.78

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $92.66 and $83.75 per Bbl and $3.21 and $2.74 per MMBtu, respectively, during the period from June 30, 2012 to August 3, 2012. At August 3, 2012, the NYMEX oil price and NYMEX natural gas price were $91.40 per Bbl and $2.88 per MMBtu, respectively.

Recent Events

Three Rivers Acquisition.In July 2012, we acquired substantially all the oil and natural gas assets of Three Rivers Operating Company and certain affiliated entities (collectively, the “Three Rivers Acquisition”) for approximately $1.0 billion in cash, subject to customary post-closing adjustments. The Three Rivers Acquisition was funded with borrowings under the credit facility. The results of operations prior to June 30, 2012 do not include results from the Three Rivers Acquisition.

Interruptions in production. During the second quarter of 2012, we experienced scheduled and unscheduled turnarounds on certain natural gas plants in New Mexico. We estimate that these interruptions reduced our second quarter 2012 production by approximately 3,000 Boe per day.

Potential divestiture.In May 2012, we announced that we were considering divestment of non-core assets partially from assets acquired in the Three Rivers Acquisition and our legacy assets. The potential divestment would, in part, provide for the financing of the Three Rivers Acquisition. There are no assurances that we will complete the divestment. A sale is dependent on numerous factors including, but not limited to, market conditions.

Credit facility amendment.In May 2012, we amended our credit facility, increasing the aggregate lender commitments from $2.0 billion to $2.5 billion, equal to our $2.5 billion borrowing base. We paid our bank group $2.2 million associated with the amendment to increase the borrowing base. At June 30, 2012, we had borrowings outstanding under our credit facility of approximately $0.4 billion, and our availability under our credit facility was approximately $2.1 billion. Pro forma for the closing of the Three Rivers Acquisition, at June 30, 2012, our availability under our credit facility would have been approximately $1.1 billion.

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

PDC Acquisition. In February 2012, we completed the PDC Acquisition for cash consideration of approximately $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.

2012 capital budget.In November 2011, we announced our 2012 capital budget of approximately $1.3 billion, which was subsequently increased to $1.37 billion in connection with the PDC Acquisition (exclusive of the $189.2 million PDC Acquisition

41

purchase price), and was again increased to $1.5 billion in connection with the Three Rivers Acquisition. Based on current commodity prices and capital costs, we believe our 2012 planned capital expenditures, excluding the effects of acquisitions, will exceed our 2012 cash flow, and we expect to fund any such shortfall with borrowings under our credit facility. We take a longer-term view on spending substantially within our cash flow, but our spending during any specific period may exceed our cash flow for that period. However, our capital budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in our drilling and completion costs, we may reduce our capital spending program to be substantially within our cash flow.

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

(in millions)	2012 Capital Budget
Drilling and completion costs:
New Mexico Shelf	$	516
Delaware Basin		482
Texas Permian		396
Acquisition of leasehold acreage and other property interests, geological and geophysical and other		58
Facilities and other capital in our core operating areas		55
Total	$	1,507

Derivative Financial Instruments

Derivative financial instrument exposure. At June 30, 2012, the fair value of our financial derivatives was a net asset of $189.8 million. All of our counterparties to these financial derivatives are parties to our credit facility and have their outstanding debt commitments and derivative exposures collateralized pursuant to our credit facility. Under the terms of our financial derivative instruments and their collateralization under our credit facility, we do not have exposure to potential “margin calls” on our financial derivative instruments. We currently have no reason to believe that our counterparties to these commodity derivative contracts are not financially viable. Our credit facility does not allow us to offset amounts we may owe a lender against amounts we may be owed related to our financial instruments with such party.

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New commodity derivative contracts.During the six months ended June 30, 2012, we entered into additional commodity derivative contracts to hedge a portion of our estimated future oil production. The following table summarizes information about these additional commodity derivative contracts for the six months ended June 30, 2012. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Aggregate Volume		Index Price(a)		Contract Period
Oil (volumes in Bbls):
Price swap		712,000	$	98.90		02/01/12 - 08/31/12
Price swap		150,000	$	98.90		02/01/12 - 11/30/12
Price swap		990,000	$	99.75		02/01/12 - 12/31/12
Price swap		145,000	$	103.65		05/01/12 - 08/31/12
Price swap		150,000	$	104.40		05/01/12 - 10/31/12
Price swap		1,000,000	$	104.00		05/01/12 - 12/31/12
Price swap		396,000	$	97.65		07/01/12 - 12/31/12
Price swap		183,000	$	98.65		01/01/13 - 03/31/13
Price swap		30,000	$	97.20		01/01/13 - 06/30/13
Price swap		230,000	$	104.30		01/01/13 - 08/31/13
Price swap		180,000	$	103.30		01/01/13 - 09/30/13
Price swap		130,000	$	97.65		01/01/13 - 10/31/13
Price swap		110,000	$	97.40		01/01/13 - 11/30/13
Price swap		3,576,000	$	98.73		01/01/13 - 12/31/13
Price swap		1,350,000	$	95.45		01/01/14 - 03/31/14
Price swap		900,000	$	98.81		01/01/14 - 06/30/14
Price swap		456,000	$	92.50		01/01/14 - 12/31/14
Price swap		450,000	$	98.52		04/01/14 - 06/30/14
Price swap		384,000	$	89.30		01/01/15 - 12/31/15
Price swap		348,000	$	88.00		01/01/16 - 12/31/16
Price swap		168,000	$	87.00		01/01/17 - 06/30/17

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

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

	Aggregate Volume		Index Price (a)		Contract Period
Oil (volumes in Bbls):
Price swap		305,000	$	90.45	08/01/12 - 12/31/12
Price swap		80,000	$	91.40	01/01/13 - 04/30/13
Price swap		44,000	$	91.35	01/01/13 - 11/30/13
Price swap		60,000	$	91.45	01/01/13 - 12/31/13
Price swap		720,000	$	89.59	01/01/14 - 06/30/14
Price swap		810,000	$	89.30	04/01/14 - 06/30/14

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

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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 and six months ended June 30, 2012 and 2011. The table below excludes production and operating data that we have classified as discontinued operations, which is more fully described in Note M of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).” The actual historical data in this table excludes results from (i) the Three Rivers Acquisition, (ii) the PDC Acquisition for periods prior to March 2012 and (iii) the OGX Acquisition for periods prior to December 2011. Because of normal production declines, increased or decreased drilling activities and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Production and operating data:
Net production volumes:
Oil (MBbl)		4,220		3,522		8,434		6,632
Natural gas (MMcf)		15,619		12,307		31,848		24,277
Total (MBoe)		6,823		5,573		13,742		10,678
Average daily production volumes:
Oil (Bbl)		46,374		38,703		46,341		36,641
Natural gas (Mcf)		171,637		135,242		174,989		134,127
Total (Boe)		74,980		61,244		75,506		58,995
Average prices:
Oil, without derivatives (Bbl)	$	85.62	$	97.32	$	91.89	$	94.27
Oil, with derivatives (Bbl)(a)	$	87.51	$	83.57	$	89.01	$	82.11
Natural gas, without derivatives (Mcf)	$	4.58	$	8.41	$	5.20	$	7.49
Natural gas, with derivatives (Mcf)(a)	$	4.60	$	8.90	$	5.22	$	7.95
Total, without derivatives (Boe)	$	63.43	$	80.07	$	68.45	$	75.58
Total, with derivatives (Boe)(a)	$	64.65	$	72.48	$	66.73	$	69.08
Operating costs and expenses per Boe:
Lease operating expenses and workover costs	$	7.52	$	5.97	$	7.40	$	6.31
Oil and natural gas taxes	$	5.33	$	6.51	$	5.69	$	6.17
Depreciation, depletion and amortization	$	20.73	$	17.74	$	20.18	$	17.72
General and administrative	$	4.69	$	4.06	$	4.32	$	4.12

(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 gain (loss) on derivatives not designated as hedges as reported in the statements of operations:

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Gain (loss) on derivatives not designated as hedges:
Cash receipts from (payments on) oil derivatives	$	7,963	$	(48,398)	$	(24,233)	$	(80,628)
Cash receipts from natural gas derivatives		324		6,076		609		11,205
Cash payments on interest rate derivatives		-		(5,429)		-		(6,624)
Unrealized mark-to-market gain (loss) on commodity and interest rate derivatives		394,763		192,633		268,581		(12,213)
Gain (loss) on derivatives not designated as hedges	$	403,050	$	144,882	$	244,957	$	(88,260)

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 gain (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 six months ended June 30, 2011. The discontinued operations presentation is the result of reclassifying the results of operations from our March 2011 Bakken divestiture, which is more fully described in Note M of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).”

	Six Months Ended June 30, 2011
Production and operating data:
Net production volumes:
Oil (MBbl)			117
Natural gas (MMcf)			37
Total (MBoe)			123
Average daily production volumes:
Oil (Bbl)			646
Natural gas (Mcf)			204
Total (Boe)			680
Average prices:
Oil, without derivatives (Bbl)		$	80.82
Oil, with derivatives (Bbl)		$	80.82
Natural gas, without derivatives (Mcf)		$	1.84
Natural gas, with derivatives (Mcf)		$	1.84
Total, without derivatives (Boe)		$	77.43
Total, with derivatives (Boe)		$	77.43
Operating costs and expenses per Boe:
Lease operating expenses and workover costs		$	3.85
Oil and natural gas taxes		$	9.50
Depreciation, depletion and amortization		$	17.13

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Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011

Oil and natural gas revenues. Revenue from oil and natural gas operations was $432.8 million for the three months ended June 30, 2012, a decrease of $13.4 million (3 percent) from $446.2 million for the three months ended June 30, 2011. This decrease was primarily due to decreases in realized oil and natural gas prices partially offset by increased production due to (i) successful drilling efforts during 2011 and 2012, (ii) production from the OGX Acquisition which closed in November 2011 and (iii) production from the PDC Acquisition which closed in February 2012. Specific factors affecting oil and natural gas revenues include the following:

• during the second quarter of 2012, we experienced delays on scheduled turnarounds on certain natural gas plants in New Mexico. We estimate that these interruptions reduced our second quarter 2012 production by approximately 250 MBoe.

• total oil production was 4,220 MBbl for the three months ended June 30, 2012, an increase of 698 MBbl (20 percent) from 3,522 MBbl for the three months ended June 30, 2011;

• average realized oil price (excluding the effects of derivative activities) was $85.62 per Bbl during the three months ended June 30, 2012, a decrease of 12 percent from $97.32 per Bbl during the three months ended June 30, 2011;

• total natural gas production was 15,619 MMcf for the three months ended June 30, 2012, an increase of 3,312 MMcf (27 percent) from 12,307 MMcf for the three months ended June 30, 2011; and

• average realized natural gas price (excluding the effects of derivative activities) was $4.58 per Mcf during the three months ended June 30, 2012, a decrease of 46 percent from $8.41 per Mcf during the three months ended June 30, 2011. Our natural gas prices have been significantly higher than the related NYMEX prices primarily due to the value of the natural gas liquids in our liquids-rich natural gas stream.

Production expenses. The following table provides the components of our total oil and natural gas production costs for the three months ended June 30, 2012 and 2011:

	Three Months Ended June 30,
	2012				2011
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Lease operating expenses	$	46,981	$	6.88	$	32,549	$	5.84
Taxes:
Ad valorem		3,948		0.58		2,676		0.48
Production		32,414		4.75		33,611		6.03
Workover costs		4,346		0.64		741		0.13
Total oil and natural gas production expenses	$	87,689	$	12.85	$	69,577	$	12.48

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 $47.0 million ($6.88 per Boe) for the three months ended June 30, 2012, which was an increase of $14.5 million (45 percent) from $32.5 million ($5.84 per Boe) for the three months ended June 30, 2011. The increase in lease operating expenses was primarily due to (i) our wells successfully drilled and completed in 2011 and 2012, (ii) the OGX and PDC Acquisitions which closed in November 2011 and February 2012, respectively, 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 and completed in 2011 and 2012 where we are receiving benefits from economies of scale.

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

Production taxes per unit of production were $4.75 per Boe during the three months ended June 30, 2012, a decrease of 21 percent from $6.03 per Boe during the three months ended June 30, 2011. The decrease was directly related to the decrease in commodity prices offset by our increase in oil and natural gas revenues related to increased volumes. Over the same period, our per Boe prices (excluding the effects of derivatives) decreased 21 percent.

Workover expenses were approximately $4.3 million and $0.7 million for the three months ended June 30, 2012 and 2011, respectively. The 2012 amounts related primarily to workovers in all areas, while the 2011 amounts related primarily to activity in the Texas Permian area performed to increase production.

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the three months ended June 30, 2012 and 2011:

	Three Months Ended June 30,
(in thousands)	2012		2011
Geological and geophysical	$	5,961	$	370
Exploratory dry holes		-		-
Leasehold abandonments and other		8,437		30
Total exploration and abandonments	$	14,398	$	400

Our geological and geophysical expense, which primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, was approximately $6.0 million and $0.4 million, primarily relating to our Delaware Basin and Texas Permian areas, for the three months ended June 30, 2012 and 2011, respectively.

For the three months ended June 30, 2012, we recorded approximately $8.4 million of leasehold abandonments, which related to non-core prospects in our 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 June 30, 2012 and 2011:

	Three Months Ended June 30,
	2012				2011
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties	$	138,199	$	20.25	$	97,298	$	17.46
Depreciation of other property and equipment		2,864		0.42		1,196	$	0.21
Amortization of intangible asset - operating rights		387		0.06		387	$	0.07
Total depletion, depreciation and amortization	$	141,450	$	20.73	$	98,881	$	17.74
Oil price used to estimate proved oil reserves at period end	$	92.17			$	86.60
Natural gas price used to estimate proved natural gas reserves at period end	$	3.15			$	4.21

Depletion of proved oil and natural gas properties was $138.2 million ($20.25 per Boe) for the three months ended June 30, 2012, an increase of $40.9 million (42 percent) from $97.3 million ($17.46 per Boe) for the three months ended June 30, 2011. The increase in depletion expense was primarily due to (i) capitalized costs associated with new wells that were successfully drilled and completed in 2011 and 2012 and (ii) production from the OGX and PDC Acquisitions which closed in November 2011 and February 2012, respectively, offset in part by the increase in the oil prices between the periods utilized to determine proved reserves. The increase in depletion expense per Boe was primarily due to (i) capitalized costs associated with a higher proportion of development wells

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successfully drilled and completed in 2012 and (ii) the decrease in natural gas prices between periods, offset in part by the increase in the oil price between periods utilized to determine proved reserves.

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

General and administrative expenses. The following table provides components of our general and administrative expenses for the three months ended June 30, 2012 and 2011:

	Three Months Ended June 30,
	2012				2011
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
General and administrative expenses	$	28,852	$	4.23	$	21,021	$	3.77
Non-cash stock-based compensation		7,347		1.08		4,725		0.85
Less: Third-party operating fee reimbursements		(4,231)		(0.62)		(3,128)		(0.56)
Total general and administrative expenses	$	31,968	$	4.69	$	22,618	$	4.06

General and administrative expenses were approximately $32.0 million ($4.69 per Boe) for the three months ended June 30, 2012, an increase of $9.4 million (42 percent) from $22.6 million ($4.06 per Boe) for the three months ended June 30, 2011. The increase in general and administrative expenses was primarily due to an increase in (i) the number of employees and related personnel expenses to handle our increased activities and (ii) non-cash stock-based compensation awards. The increase in general and administrative expenses per Boe was primarily due to 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 2011 and 2012, (ii) additional production from our OGX and PDC Acquisitions for which we acquired no new general and administrative personnel 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 $3.1 million during the three months ended June 30, 2012 and 2011, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations.

Gain 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 June 30, 2012 and 2011:

	Three Months Ended June 30,
(in thousands)	2012		2011
Cash payments (receipts):
Commodity derivatives - oil	$	(7,963)	$	48,398
Commodity derivatives - natural gas		(324)		(6,076)
Financial derivatives - interest		-		5,429
Mark-to-market (gain) loss:
Commodity derivatives - oil		(395,128)		(192,566)
Commodity derivatives - natural gas		365		4,802
Financial derivatives - interest		-		(4,869)
Gain on derivatives not designated as hedges	$	(403,050)	$	(144,882)

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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 June 30, 2012 and 2011:

	Three Months Ended June 30,
(dollars in thousands)	2012		2011
Interest expense	$	41,899	$	21,660
Weighted average interest rate		6.1%		5.9%
Weighted average debt balance	$	2,435,588	$	1,740,117

The increase in weighted average debt balance during the three months ended June 30, 2012 was due primarily to (i) borrowings for the OGX and PDC Acquisitions in November 2011 and February 2012, respectively, (ii) capital expenditures and (iii) the deposit related to the Three Rivers Acquisition in May 2012. The increase in interest expense was due to (i) additional borrowings overall, (ii) the May 2011 issuance of our 6.5% senior notes due 2021 (iii) the March 2012 issuance of our 5.5% senior notes due 2022 and (iv) the amortization of capitalized loan costs associated with debt financing, partially offset by the repayment of a $150 million 8.0% senior note in May 2011.

Income tax provisions. We recorded an income tax expense of $197.6 million and $143.3 million for the three months ended June 30, 2012 and 2011, respectively. The effective income tax rate for each of the three months ended June 30, 2012 and 2011 was 38.2 percent.

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Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Oil and natural gas revenues. Revenue from oil and natural gas operations was $940.6 million for the six months ended June 30, 2012, an increase of $133.5 million (17 percent) from $807.1 million for the six months ended June 30, 2011. This increase was primarily due to increased production due to (i) successful drilling efforts during 2011 and 2012, (ii) production from the OGX Acquisition which closed in November 2011 and (iii) production from the PDC Acquisition which closed in February 2012, partially offset by decreases in realized oil and natural gas prices. Specific factors affecting oil and natural gas revenues include the following:

• during the second quarter of 2012, we experienced delays on scheduled turnarounds on certain natural gas plants in New Mexico. We estimate that these interruptions reduced our second quarter 2012 production by approximately 250 MBoe.

• total oil production was 8,434 MBbl for the six months ended June 30, 2012, an increase of 1,802 MBbl (27 percent) from 6,632 MBbl for the six months ended June 30, 2011;

• average realized oil price (excluding the effects of derivative activities) was $91.89 per Bbl during the six months ended June 30, 2012, a decrease of 3 percent from $94.27 per Bbl during the six months ended June 30, 2011;

• total natural gas production was 31,848 MMcf for the six months ended June 30, 2012, an increase of 7,571 MMcf (31 percent) from 24,277 MMcf for the six months ended June 30, 2011; and

• average realized natural gas price (excluding the effects of derivative activities) was $5.20 per Mcf during the six months ended June 30, 2012, a decrease of 31 percent from $7.49 per Mcf during the six months ended June 30, 2011. Our natural gas prices have been significantly higher than the related NYMEX prices primarily due to the value of the natural gas liquids in our liquids-rich natural gas stream.

Production expenses. The following table provides the components of our total oil and natural gas production costs for the six months ended June 30, 2012 and 2011:

	Six Months Ended June 30,
	2012				2011
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Lease operating expenses	$	95,323	$	6.94	$	66,462	$	6.23
Taxes:
Ad valorem		7,036		0.52		5,342	$	0.50
Production		71,101		5.17		60,563	$	5.67
Workover costs		6,379		0.46		868	$	0.08
Total oil and natural gas production expenses	$	179,839	$	13.09	$	133,235	$	12.48

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 $95.3 million ($6.94 per Boe) for the six months ended June 30, 2012, which was an increase of $28.8 million (43 percent) from $66.5 million ($6.23 per Boe) for the six months ended June 30, 2011. The increase in lease operating expenses was primarily due to (i) our wells successfully drilled and completed in 2011 and 2012, (ii) the OGX and PDC Acquisitions which closed in November 2011 and February 2012, respectively, 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 (i) an increase in cost of services, primarily labor related, due to the increased demand for services and related labor in the Permian Basin and (ii) incurrence of higher than normal routine environmental related costs, offset in part by additional production from our wells successfully drilled and completed in 2011 and 2012 where we are receiving benefits from economies of scale.

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

Production taxes per unit of production were $5.17 per Boe during the six months ended June 30, 2012, a decrease of 9 percent from $5.67 per Boe during the six months ended June 30, 2011. The decrease was directly related to the decrease in commodity prices offset by our increase in oil and natural gas revenues related to increased volumes. Over the same period, our per Boe prices (excluding the effects of derivatives) decreased 9 percent.

Workover expenses were approximately $6.4 million and $0.9 million for the six months ended June 30, 2012 and 2011, respectively. The 2012 amounts related primarily to workovers in the New Mexico Shelf and Texas Permian areas, while the 2011 amounts related primarily to activity in the Texas Permian area performed to increase production.

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the six months ended June 30, 2012 and 2011:

	Six Months Ended June 30,
(in thousands)	2012		2011
Geological and geophysical	$	8,838	$	958
Exploratory dry holes		2,982		12
Leasehold abandonments and other		8,557		156
Total exploration and abandonments	$	20,377	$	1,126

Our geological and geophysical expense, which primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, was approximately $8.8 million and $1.0 million, primarily relating to our Delaware Basin and Texas Permian areas, for the six months ended June 30, 2012 and 2011, respectively.

Our exploratory dry hole expense during the six months ended June 30, 2012 was primarily related to expensing an unsuccessful lateral on a well that was the result of mechanical issues in the Delaware Basin.

For the six months ended June 30, 2012, we recorded approximately $8.6 million of leasehold abandonments, which related to non-core prospects in our New Mexico Shelf area.

Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the six months ended June 30, 2012 and 2011:

	Six Months Ended June 30,
	2012				2011
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties	$	271,366	$	19.75	$	186,241	$	17.44
Depreciation of other property and equipment		5,179		0.38		2,154		0.20
Amortization of intangible asset - operating rights		774		0.05		774		0.08
Total depletion, depreciation and amortization	$	277,319	$	20.18	$	189,169	$	17.72
Oil price used to estimate proved oil reserves at period end	$	92.17			$	86.60
Natural gas price used to estimate proved natural gas reserves at period end	$	3.15			$	4.21

Depletion of proved oil and natural gas properties was $271.4 million ($19.75 per Boe) for the six months ended June 30, 2012, an increase of $85.2 million (46 percent) from $186.2 million ($17.44 per Boe) for the six months ended June 30, 2011. The increase in depletion expense was primarily due to (i) capitalized costs associated with new wells that were successfully drilled and completed

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in 2011 and 2012 and (ii) production from the OGX and PDC Acquisitions which closed in November 2011 and February 2012, respectively, offset in part by the increase in the oil prices between the periods utilized to determine proved reserves. The increase in depletion expense per Boe was primarily due to (i) capitalized costs associated with a higher proportion of development wells successfully drilled and completed in 2012 and (ii) the decrease in natural gas prices between periods, offset in part by the increase in the oil price between periods utilized to determine proved reserves.

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

General and administrative expenses. The following table provides components of our general and administrative expenses for the six months ended June 30, 2012 and 2011:

	Six Months Ended June 30,
	2012				2011
(in thousands, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
General and administrative expenses	$	53,943	$	3.93	$	40,532	$	3.80
Non-cash stock-based compensation		13,475		0.98		9,193		0.86
Less: Third-party operating fee reimbursements		(8,063)		(0.59)		(5,715)		(0.54)
Total general and administrative expenses	$	59,355		4.32	$	44,010	$	4.12

General and administrative expenses were $59.4 million ($4.32 per Boe) for the six months ended June 30, 2012, an increase of $15.4 million (35 percent) from $44.0 million ($4.12 per Boe) for the six months ended June 30, 2011. The increase in general and administrative expenses was primarily due to an increase in (i) the number of employees and related personnel expenses to handle our increased activities and (ii) non-cash stock-based compensation awards. The increase in total general and administrative expenses per Boe was primarily due to 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 2011 and 2012, (ii) additional production from our OGX and PDC Acquisitions for which we acquired no new general and administrative personnel 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 $8.1 million and $5.7 million during the six months ended June 30, 2012 and 2011, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations.

(Gain) loss on derivatives not designated as hedges. The following table sets forth the cash settlements and the non-cash mark-to-market adjustments for the derivative contracts not designated as hedges for the six months ended June 30, 2012 and 2011:

	Six Months Ended June 30,
(in thousands)	2012		2011
Cash payments (receipts):
Commodity derivatives - oil	$	24,233	$	80,628
Commodity derivatives - natural gas		(609)		(11,205)
Financial derivatives - interest		-		6,624
Mark-to-market (gain) loss:
Commodity derivatives - oil		(269,020)		8,942
Commodity derivatives - natural gas		439		9,025
Financial derivatives - interest		-		(5,754)
(Gain) loss on derivatives not designated as hedges	$	(244,957)	$	88,260

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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 six months ended June 30, 2012 and 2011:

	Six Months Ended
	June 30,
(dollars in thousands)	2012		2011
Interest expense	$	77,736	$	51,320
Weighted average interest rate		5.9%		5.8%
Weighted average debt balance	$	2,311,566	$	1,724,911

The increase in weighted average debt balance during the six months ended June 30, 2012 was due primarily to (i) borrowings for the OGX and PDC Acquisitions in November 2011 and February 2012, respectively, (ii) capital expenditures and (iii) the deposit related to the Three Rivers Acquisition in May 2012. The increase in interest expense was due to (i) additional borrowings overall, (ii) the May 2011 and March 2012 senior notes issuances having higher interest rates than borrowings under our credit facility and (iii) the amortization of capitalized loan costs associated with debt financing, partially offset by the repayment of a $150 million 8.0% senior note in May 2011.

Income tax provisions. We recorded an income tax expense of $216.7 million and $112.8 million for the six months ended June 30, 2012 and 2011, respectively. The effective income tax rate for the six months ended June 30, 2012 and 2011 was 38.2 percent and 38.1 percent, respectively.

Income from discontinued operations, net of tax.In March 2011, we sold our Bakken assets for cash consideration of approximately $195.9 million. We recognized income from discontinued operations of $91.2 million for the six months ended June 30, 2011. In 2011, after completion of the final post-closing adjustments, we recognized a pre-tax gain on the sale of assets of approximately $135.9 million; however, through the six months ended June 30, 2011, our results of operations reflected a pre-tax gain on sale of assets of approximately $142.0 million. We have reflected the results of operations of these divested assets as discontinued operations, rather than as a component of continuing operations. See Note M of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding these divestitures and their discontinued operations.

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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 six months ended June 30, 2012 and 2011 totaled $725.7 million and $605.0 million, respectively. The primary reason for the differences in the costs incurred and cash flow expenditures is the timing of payments. The 2012 expenditures were funded in part from borrowings under our credit facility.

In November 2011, we announced our 2012 capital budget of approximately $1.3 billion, which was subsequently increased to $1.37 billion in connection with the PDC Acquisition (exclusive of the $189.2 million PDC Acquisition purchase price), and was again increased to $1.5 billion in connection with the Three Rivers Acquisition. Based on current commodity prices and capital costs, we believe our 2012 planned capital expenditures, excluding the effects of acquisitions, will exceed our 2012 cash flow, and we expect to fund any such shortfall with borrowings under our credit facility.

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

Other than the customary purchase of leasehold acreage, our 2012 capital budget is exclusive of acquisitions. We do not have a specific acquisition budget, since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek to acquire oil and natural gas properties that provide opportunities for the addition of reserves and production through a combination of development, high-potential exploration and control of operations that will allow us to apply our operating expertise.

Acquisitions.Our expenditures for acquisitions of proved and unproved properties during the three months ended June 30, 2012 and 2011 totaled approximately $27.4 million and $21.4 million, respectively, and approximately $226.8 million and $144.5 million during the six months ended June 30, 2012 and 2011, respectively. The acquisitions of proved properties during the six months ended June 30, 2012 primarily relate to additional Texas Permian and Delaware Basin assets. Expenditures for leasehold acreage acquisitions (which are expenditures we generally provide for in the budget) included in the total above were approximately $16.1 million and $45.9 million for the six months ended June 30, 2012 and 2011, respectively.

Divestitures.In March 2011, we sold our Bakken assets for cash consideration of approximately $195.9 million. In 2011, after completion of the final post-closing adjustments, we recognized a pre-tax gain on the sale of assets of approximately $135.9 million; however, through the three months ended June 30, 2011, our results of operations reflected a pre-tax gain on sale of assets of approximately $142.0 million. For 2011, these assets produced an average of approximately 1,369 Boe per day, of which approximately 95 percent was oil. We used the net proceeds from this divestiture to initially repay a portion of the outstanding borrowings under our credit facility.

Contractual obligations.Our contractual obligations include long-term debt, cash interest expense on debt, operating lease obligations, drilling commitments, employment agreements with officers, derivative liabilities and other obligations. Since December 31, 2011, the material changes in our contractual obligations included a $443.2 million increase in outstanding long-term debt, a $270.4 million increase in cash interest expense on debt and a $268.6 million decrease in our net commodity derivative liability, which resulted in a net asset position. See Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our long-term debt and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for information regarding the interest on our long-term debt and information on changes in the fair value of our open derivative obligations during the six months ended June 30, 2012.

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

Capital resources. Our primary sources of liquidity have been cash flows generated from operating activities (including the cash settlements received from (paid on) derivatives not designated as hedges presented in our investing activities) and financing provided

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by our credit facility. Based on current commodity prices and capital costs, we believe our 2012 planned capital expenditures, excluding the effects of acquisitions, will exceed our 2012 cash flow, and we expect to fund any such shortfall with borrowings under our credit facility. We believe that we have adequate availability under our credit facility to fund any cash flow deficits, though we could reduce our capital spending program to remain substantially within our cash flow.

The following table summarizes our net increase in cash and cash equivalents for the six months ended June 30, 2012 and 2011:

	Six Months Ended June 30,
(in thousands)	2012		2011
Net cash provided by operating activities	$	610,965	$	485,847
Net cash used in investing activities		(1,046,571)		(581,948)
Net cash provided by financing activities		435,974		96,114
Net increase in cash and cash equivalents	$	368	$	13

Cash flow from operating activities.The increase in operating cash flows during the six months ended June 30, 2012 over 2011 was principally due to increases in our oil and natural gas production as a result of (i) our exploration and development program and (ii) the OGX and PDC Acquisitions which closed in November 2011 and February 2012, respectively; offset in part by decreases in average realized oil and natural gas prices and increases in oil and natural gas production costs.

Our net cash provided by operating activities also includes a reduction of $7.3 million and $96.2 million for the six months ended June 30, 2012 and 2011, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

Cash flow used in investing activities.During the six months ended June 30, 2012 and 2011, we invested $949.1 million and $677.2 million, respectively, for capital expenditures on oil and natural gas properties. Cash flows used in investing activities were higher during the six months ended June 30, 2012 as compared to 2011, due to an increase in our capital expenditures on oil and natural gas properties and a decrease in the proceeds from the sale of assets.

Cash flow from financing activities.During the six months ended June 30, 2012 and 2011 we completed the following significant activities:

• In May 2012, we amended our credit facility, increasing the aggregate lender commitments from $2.0 billion to $2.5 billion, equal to our $2.5 billion borrowing base. We paid our bank group $2.2 million associated with the amendment to increase the borrowing base.

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

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

Our credit facility has a maturity date of April 25, 2016. Our borrowing base is $2.5 billion until the next scheduled borrowing base redetermination in October 2012. Between scheduled borrowing base redeterminations, the Company and the lenders (requiring a 66 2/3 percent vote), may each request one special redetermination. At June 30, 2012, we had no letters of credit outstanding under the credit facility, and our availability to borrow additional funds was approximately $2.1 billion based on bank commitments of $2.5 billion. Pro forma for the closing of the Three Rivers Acquisition, at June 30, 2012, our availability under our credit facility would have been approximately $1.1 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 June 30, 2012) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). The credit facility’s interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest margins ranging from 150 to 250 basis points and 50 to 150 basis points, respectively, per annum depending on the debt balance outstanding. We pay commitment fees on the unused portion of the available commitment ranging from 37.5 to 50 basis points per annum, depending on utilization of the commitments.

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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 June 30, 2012, we had $0.7 million of cash on hand.

At June 30, 2012, the commitments under our credit facility were $2.5 billion, which provided us with approximately $2.1 billion of available borrowing capacity. Pro forma for the closing of the Three Rivers Acquisition, at June 30, 2012, our availability under our credit facility would have been approximately $1.1 billion. Upon a redetermination, our $2.5 billion borrowing base could be substantially reduced. There is no assurance that our borrowing base will not be reduced, which could affect our liquidity.

Debt ratings.We receive debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”), which are subject to regular reviews. S&P’s corporate rating for us is “BB+” with a stable outlook. Moody’s corporate rating for us is “Ba3” with a 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 June 30, 2012 was $5.9 billion, consisting of debt of $2.5 billion and stockholders’ equity of $3.4 billion. Our debt to book capitalization was 43 percent and 41 percent at June 30, 2012 and December 31, 2011, respectively. Pro forma for the closing of the Three Rivers Acquisition, at June 30, 2012, our debt to book capitalization would have been 51 percent. Our ratio of current assets to current liabilities was 0.74 to 1.0 at June 30, 2012 as compared to 0.59 to 1.0 at December 31, 2011.

Inflation and changes in prices. Our revenues, the value of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the six months ended June 30, 2012, we received an average of $91.89 per barrel of oil and $5.20 per Mcf of natural gas before consideration of commodity derivative contracts compared to $94.27 per barrel of oil and $7.49 per Mcf of natural gas in the six months ended June 30, 2011. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004, and that has continued 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 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 six months ended June 30, 2012. See our disclosure of critical accounting policies in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the United States Securities and Exchange Commission (the “SEC”) on February 24, 2012.

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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, 2011.

We are exposed to a variety of market risks including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we are a party at June 30, 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.

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

Commodity price risk. We are exposed to market risk as the prices of oil and natural gas are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of oil and natural gas we have entered into, and may in the future enter into additional, commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Our commodity price risk management activities could have the effect of reducing net income and the value of our securities. An average increase in the commodity price of $10.00 per barrel of oil and $1.00 per MMBtu for natural gas from the commodity prices at June 30, 2012, would have resulted in a net unrealized loss on our commodity price risk management contracts of approximately $254.8 million.

At June 30, 2012, we had (i) oil price swaps that settle on a monthly basis covering future oil production from July 1, 2012 through June 30, 2017 and (ii) natural gas price swaps, natural gas price collars and natural gas basis swaps covering future natural gas production from July 1, 2012 to December 31, 2012. See Note H of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on our commodity derivative instruments. The average NYMEX oil price and average NYMEX natural gas prices for the six months ended June 30, 2012, was $98.19 per Bbl and $2.44 per MMBtu, respectively. At August 3, 2012, the NYMEX oil price and NYMEX natural gas price were $91.40 per Bbl and $2.88 per MMBtu, respectively. A decrease in the average NYMEX oil and natural gas prices below those at June 30, 2012, would decrease the fair value liability of our commodity derivative contracts from their recorded balance at June 30, 2012. Changes in the recorded fair value of the undesignated commodity derivative contracts are marked to market through earnings as unrealized gains or losses. The potential decrease in our fair value liability would be recorded in earnings as an unrealized gain. However, an increase in the average NYMEX oil and natural gas prices above those at June 30, 2012, would increase the fair value liability of our commodity derivative contracts from their recorded balance at June 30, 2012. The potential increase in our fair value liability would be recorded in earnings as an unrealized loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.

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

We had total indebtedness of $426.5 million outstanding under our credit facility at June 30, 2012. The impact of a 1 percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $4.3 million.

The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method during the three months ended June 30, 2012. During the three months ended June 30, 2012, we were party to commodity derivative instruments. See Note H of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the three months ended June 30, 2012:

(in thousands)	Commodity Derivative Instruments Net Assets (Liabilities) (a)
Fair value of contracts outstanding at December 31, 2011	$	(78,830	)
Changes in fair values(b)		244,957
Contract maturities		23,625
Fair value of contracts outstanding at June 30, 2012	$	189,752

(a) Represents the fair values of open derivative contracts subject to market risk.

(b) At inception, new derivative contracts entered into by us have no intrinsic value.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at June 30, 2012 at the reasonable assurance level.

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

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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 quarter-by-quarter basis and will establish and adjust any reserves as appropriate to reflect our assessment of the then current status of the matters.

Item 1A. Risk Factors

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

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

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
April 1, 2012 - April 30, 2012		696	$	105.00		-
May 1, 2012 - May 31, 2012		4,674	$	97.27		-
June 1, 2012 - June 30, 2012		-	$	-		-

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

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Item 6. Exhibits

Exhibit Number	Exhibit
2.1*	Purchase Agreement, dated May 11, 2012, by and among COG Operating LLC, as purchaser, and Three Rivers Acquisition LLC and Three Rivers Operating Company LLC, as sellers (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on May 11, 2012, and incorporated herein by reference).
3.1	Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).
3.2	Amended and Restated Bylaws of Concho Resources Inc., as amended March 25, 2008 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on March 26, 2008, and incorporated herein by reference).
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A on July 5, 2007, and incorporated herein by reference).
4.2	Sixth Supplemental Indenture, dated March 12, 2012, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).
4.3	Form of 5.5% Senior Notes due 2022 (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).
10.1	Amended and Restated Concho Resources Inc. 2006 Stock Incentive plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 11, 2012, and incorporated herein by reference).
10.2	Eighth Amendment to Amended and Restated Credit Agreement, dated as of April 12, 2012, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 16, 2012, and incorporated herein by reference).
10.3	Ninth Amendment to Amended and Restated Credit Agreement, dated as of May 31, 2012, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 5, 2012, and incorporated herein by reference).
31.1 (a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 (a)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 (b)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 (b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS (a)	XBRL Instance Document.
101.SCH (a)	XBRL Schema Document.
101.CAL (a)	XBRL Calculation Linkbase Document.
101.DEF (a)	XBRL Definition Linkbase Document.
101.LAB (a)	XBRL Labels Linkbase Document.
101.PRE (a)	XBRL Presentation Linkbase Document.

(a) Filed herewith.

(b) Furnished herewith.

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

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SIGNATURES

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

		CONCHO RESOURCES INC.
Date:	August 8, 2012	By	/s/ Timothy A. Leach
			Timothy A. Leach
			Director, Chairman of the Board of Directors, Chief Executive
			Officer and President (Principal Executive Officer)
		By
			/s/ Darin G. Holderness
			Darin G. Holderness
			Senior Vice President, Chief Financial Officer and Treasurer
			(Principal Financial Officer)
		By
			/s/ Don O. McCormack
			Don O. McCormack
			Vice President and Chief Accounting Officer
			(Principal Accounting Officer)

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EXHIBIT INDEX

Exhibit Number	Exhibit
2.1*	Purchase Agreement, dated May 11, 2012, by and among COG Operating LLC, as purchaser, and Three Rivers Acquisition LLC and Three Rivers Operating Company LLC, as sellers (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on May 11, 2012, and incorporated herein by reference).
3.1	Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).
3.2	Amended and Restated Bylaws of Concho Resources Inc., as amended March 25, 2008 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on March 26, 2008, and incorporated herein by reference).
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A on July 5, 2007, and incorporated herein by reference).
4.2	Sixth Supplemental Indenture, dated March 12, 2012, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).
4.3	Form of 5.5% Senior Notes due 2022 (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).
10.1	Amended and Restated Concho Resources Inc. 2006 Stock Incentive plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 11, 2012, and incorporated herein by reference).
10.2	Eighth Amendment to Amended and Restated Credit Agreement, dated as of April 12, 2012, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 16, 2012, and incorporated herein by reference).
10.3	Ninth Amendment to Amended and Restated Credit Agreement, dated as of May 31, 2012, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 5, 2012, and incorporated herein by reference).
31.1 (a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 (a)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 (b)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 (b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS (a)	XBRL Instance Document.
101.SCH (a)	XBRL Schema Document.
101.CAL (a)	XBRL Calculation Linkbase Document.
101.DEF (a)	XBRL Definition Linkbase Document.
101.LAB (a)	XBRL Labels Linkbase Document.
101.PRE (a)	XBRL Presentation Linkbase Document.

(a) Filed herewith.

(b) Furnished herewith.

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