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 September 30, 2011

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

(432) 683-7443

(Registrant’s telephone number, including area code)

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

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 November 1, 2011: 103,683,181 shares

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION	iii
Item 1. Consolidated Financial Statements (Unaudited)	iii
Item  2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 3. Quantitative and Qualitative Disclosures About Market Risk	63
Item 4. Controls and Procedures	64
PART II – OTHER INFORMATION	65
Item 1. Legal Proceedings	65
Item 1A. Risk Factors	65
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	67
Item 5. Other Information	67
Item 6. Exhibits	68

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 securities law, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2010, our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 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;

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

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

• risks and liabilities associated with acquired properties or businesses;

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

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

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

• competition in the oil and natural gas industry; 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 September 30, 2011 and December 31, 2010	1
Consolidated Statements of Operations for the Three and Nine Months Ended September  30, 2011 and 2010	2
Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2011	3
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010	4
Condensed Notes to Consolidated Financial Statements	5

iii

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited

(in thousands, except share and per share data)	September 30, 2011		December 31, 2010
Assets
Current assets:
Cash and cash equivalents	$	174	$	384
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas		216,832		136,471
Joint operations and other		168,935		131,912
Related parties		103		169
Derivative instruments		145,671		6,855
Deferred income taxes		-		42,716
Prepaid costs and other		15,381		12,126
Total current assets		547,096		330,633
Property and equipment:
Oil and natural gas properties, successful efforts method		6,687,087		5,616,249
Accumulated depletion and depreciation		(995,261)		(730,509)
Total oil and natural gas properties, net		5,691,826		4,885,740
Other property and equipment, net		53,791		28,047
Total property and equipment, net		5,745,617		4,913,787
Deferred loan costs, net		68,297		52,828
Intangible asset - operating rights, net		33,811		34,973
Inventory		26,349		28,342
Noncurrent derivative instruments		90,752		2,233
Other assets		10,864		5,698
Total assets	$	6,522,786	$	5,368,494
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	6,781	$	39,943
Related parties		25		1,197
Other current liabilities:
Bank overdrafts		56,892		12,314
Revenue payable		143,605		57,406
Accrued and prepaid drilling costs		291,151		215,079
Derivative instruments		1,960		97,775
Deferred income taxes		52,521		-
Other current liabilities		108,751		83,275
Total current liabilities		661,686		506,989
Long-term debt		1,789,532		1,668,521
Deferred income taxes		972,346		720,889
Noncurrent derivative instruments		-		51,647
Asset retirement obligations and other long-term liabilities		41,583		36,574
Commitments and contingencies (Note K)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 103,724,471 and 102,842,082 shares issued at September 30, 2011 and December 31, 2010, respectively		104		103
Additional paid-in capital		1,919,397		1,874,649
Retained earnings		1,141,699		510,737
Treasury stock, at cost; 51,499 and 31,963 shares at September 30, 2011 and December 31, 2010, respectively		(3,561)		(1,615)
Total stockholders’ equity		3,057,639		2,383,874
Total liabilities and stockholders’ equity	$	6,522,786	$	5,368,494

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

1

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands, except per share amounts)	2011		2010 (a)		2011		2010 (a)
Operating revenues:
Oil sales	$	332,659	$	177,601	$	957,833	$	489,681
Natural gas sales		121,809		48,190		303,707		134,598
Total operating revenues		454,468		225,791		1,261,540		624,279
Operating costs and expenses:
Oil and natural gas production		84,050		41,762		217,285		111,534
Exploration and abandonments		3,498		3,617		4,624		5,648
Depreciation, depletion and amortization		115,730		57,624		304,899		157,394
Accretion of discount on asset retirement obligations		751		349		2,170		1,006
Impairments of long-lived assets		-		1,922		76		5,667
General and administrative (including non-cash stock-based compensation of $4,673 and $3,152 for the three months ended September 30, 2011 and 2010, respectively, and $13,866 and $8,854 for the nine months ended September 30, 2011 and 2010, respectively)		22,873		15,285		66,883		46,824
Bad debt expense		-		6		-		578
(Gain) loss on derivatives not designated as hedges		(385,222)		66,107		(296,962)		(62,229)
Total operating costs and expenses		(158,320)		186,672		298,975		266,422
Income from operations		612,788		39,119		962,565		357,857
Other income (expense):
Interest expense		(32,881)		(12,036)		(84,201)		(34,293)
Other, net		(2,503)		(3,521)		(4,590)		(3,898)
Total other expense		(35,384)		(15,557)		(88,791)		(38,191)
Income from continuing operations before income taxes		577,404		23,562		873,774		319,666
Income tax expense		(221,199)		(7,392)		(334,000)		(118,375)
Income from continuing operations		356,205		16,170		539,774		201,291
Income from discontinued operations, net of tax		-		4,605		91,188		11,195
Net income	$	356,205	$	20,775	$	630,962	$	212,486
Basic earnings per share:
Income from continuing operations	$	3.47	$	0.18	$	5.27	$	2.23
Income from discontinued operations, net of tax		-		0.05		0.88		0.12
Net income per share	$	3.47	$	0.23	$	6.15	$	2.35
Weighted average shares used in basic earnings per share		102,733		91,182		102,517		90,361
Diluted earnings per share:
Income from continuing operations	$	3.44	$	0.18	$	5.21	$	2.20
Income from discontinued operations, net of tax		-		0.04		0.88		0.12
Net income per share	$	3.44	$	0.22	$	6.09	$	2.32
Weighted average shares used in diluted earnings per share		103,696		92,440		103,613		91,631

(a)   Retrospectively adjusted for presentation of discontinued operations as described in Note B.

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, 2010		102,842	$	103	$	1,874,649	$	510,737		32	$	(1,615)	$	2,383,874
Net income		-		-		-		630,962		-		-		630,962
Stock options exercised		652		1		7,660		-		-		-		7,661
Grants of restricted stock		276		-		-		-		-		-		-
Cancellation of restricted stock		(46)		-		-		-		-		-		-
Stock-based compensation		-		-		13,866		-		-		-		13,866
Excess tax benefits related to stock-based compensation		-		-		23,222		-		-		-		23,222
Purchase of treasury stock		-		-		-		-		19		(1,946)		(1,946)
BALANCE AT SEPTEMBER 30, 2011		103,724	$	104	$	1,919,397	$	1,141,699		51	$	(3,561)	$	3,057,639

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

3

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited

	Nine Months Ended September 30,
(in thousands)	2011		2010 (a)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	630,962	$	212,486
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		304,899		157,394
Impairments of long-lived assets		76		5,667
Accretion of discount on asset retirement obligations		2,170		1,006
Exploration and abandonments, including dry holes		807		3,995
Non-cash compensation expense		13,866		8,854
Bad debt expense		-		578
Deferred income taxes		312,199		107,261
Loss on sale of assets		3,129		24
Gain on derivatives not designated as hedges		(296,962)		(62,229)
Discontinued operations		(82,118)		19,041
Other non-cash items		309		3,760
Changes in operating assets and liabilities:
Accounts receivable		(125,091)		(35,505)
Prepaid costs and other		(8,420)		(700)
Inventory		1,204		(4,673)
Accounts payable		(34,334)		(8,127)
Revenue payable		86,199		9,716
Other current liabilities		(29,909)		(15,792)
Net cash provided by operating activities		778,986		402,756
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and natural gas properties		(932,770)		(486,903)
Acquisition of oil and natural gas properties		(113,438)		(17,730)
Additions to other property and equipment		(29,954)		(3,750)
Proceeds from the sale of assets		196,252		790
Settlements paid on derivatives not designated as hedges		(77,835)		(5,231)
Net cash used in investing activities		(957,745)		(512,824)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		2,079,000		840,500
Payments of long-term debt		(1,949,500)		(998,000)
Net proceeds from issuance of common stock		-		219,308
Exercise of stock options		7,661		4,371
Excess tax benefit related to stock-based compensation		23,222		8,968
Payments for loan origination costs		(24,466)		(2,299)
Purchase of treasury stock		(1,946)		(793)
Bank overdrafts		44,578		35,136
Net cash provided by financing activities		178,549		107,191
Net decrease in cash and cash equivalents		(210)		(2,877)
Cash and cash equivalents at beginning of period		384		3,234
Cash and cash equivalents at end of period	$	174	$	357
SUPPLEMENTAL CASH FLOWS:
Cash paid for interest and fees, net of $73 and $119 capitalized interest	$	60,752	$	27,627
Cash paid for income taxes	$	15,610	$	17,771

(a)   Retrospectively adjusted for presentation of discontinued operations as described in Note B.

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

4

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Note A. Organization and nature of operations

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

Note B. Summary of significant accounting policies

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

Discontinued operations. The Company made the following divestitures of assets:

	Asset Group
(dollars in millions)	Permian Basin Assets		Bakken Assets
Date divested		December 2010		March 2011
Net proceeds	$	103.3	$	195.9
Gain on sale of assets	$	29.1	$	142.0

As a result, 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 N 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 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 costs during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of derivative financial instruments, fair value measurements of business combinations and oil and natural gas property acquisitions and fair value of stock-based compensation.

Interim financial statements. The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2010 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 September 30, 2011, its results of operations for the three and nine months ended September 30, 2011 and 2010, and its cash flows for the nine months ended September 30, 2011 and 2010. All such adjustments are normal and recurring. 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

5

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

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 Current Report on Form 8-K, which amended and replaced certain portions of the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, filed with the United States Securities and Exchange Commission (the “SEC”) on May 18, 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.

Future amortization expense of deferred loan costs at September 30, 2011 was as follows:

(in thousands)
Remaining 2011	$	2,655
2012		10,758
2013		10,986
2014		11,232
2015		11,499
Thereafter		21,167
Total	$	68,297

Intangible assets. The Company 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 September 30, 2011 and December 31, 2010:

(in thousands)	September 30, 2011		December 31, 2010
Gross intangible - operating rights	$	38,717	$	38,717
Accumulated amortization		(4,906)		(3,744)
Net intangible - operating rights	$	33,811	$	34,973

The following table reflects amortization expense for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Amortization expense	$	388	$	388	$	1,162	$	1,162

6

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

The following table reflects the estimated aggregate amortization expense for each of the periods presented below at September 30, 2011:

(in thousands)
Remaining 2011	$	388
2012		1,549
2013		1,549
2014		1,549
2015		1,549
Thereafter		27,227
Total	$	33,811

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

The following tables reflect the Company’s natural gas imbalance positions at September 30, 2011 and December 31, 2010, as well as amounts reflected in oil and natural gas production expense for the three and nine months ended September 30, 2011 and 2010:

(dollars in thousands)					September 30, 2011		December 31, 2010
Natural gas imbalance receivable (included in other assets)					$	100	$	100
Undertake position (Mcf)						22,220		22,240
Natural gas imbalance liability (included in asset retirement obligations and other long-term liabilities)					$	432	$	403
Overtake position (Mcf)						78,068		71,153
	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Value of net overtake (undertake) arising during the period increasing oil and natural gas production expense	$	-	$	(14)	$	29	$	(9)
Net overtake (undertake) position arising during the period (Mcf)		-		(3,221)		6,935		(2,213)

7

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

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

General and administrative expense. The Company receives fees for the operation of jointly owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees from continuing and discontinued operations totaled approximately $3.6 million and $3.5 million for the three months ended September 30, 2011 and 2010, respectively, and $9.3 million and $10.0 million for the nine months ended September 30, 2011 and 2010, respectively.

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 nine months ended September 30, 2011:

(in thousands)	Three Months Ended September 30, 2011		Nine Months Ended September 30, 2011
Beginning capitalized exploratory well costs	$	111,884	$	46,826
Additions to exploratory well costs pending the determination of proved reserves		221,768		360,030
Reclassifications due to determination of proved reserves		(219,430)		(292,634)
Exploratory well costs charged to expense		-		-
Ending capitalized exploratory well costs	$	114,222	$	114,222

The following table provides an aging, at September 30, 2011 and December 31, 2010, of capitalized exploratory well costs based on the date drilling was completed:

(in thousands)	September 30, 2011		December 31, 2010
Exploratory wells in progress	$	20,234	$	19,190
Capitalized exploratory well costs that have been capitalized for a period of one year or less		93,988		27,636
Capitalized exploratory well costs that have been capitalized for a period greater than one year		-		-
Total capitalized exploratory well costs	$	114,222	$	46,826

At September 30, 2011, the Company had 75 gross exploratory wells either drilling or waiting on results from completion. There were 16 wells in the Texas Permian area, 31 in the Delaware Basin area and 28 wells in the New Mexico Shelf area.

8

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Note D. Acquisitions and business combinations

Marbob and Settlement Acquisitions. In July 2010, the Company entered into an asset purchase agreement to acquire certain of the oil and natural gas leases, interests, properties and related assets owned by Marbob Energy Corporation and its affiliates (collectively, “Marbob”) for aggregate consideration of (i) cash in the amount of $1.45 billion, (ii) the issuance to Marbob of a $150 million 8.0% unsecured senior note due 2018 and (iii) the issuance to Marbob of approximately 1.1 million shares of the Company’s common stock, subject to purchase price adjustments, which included downward purchase price adjustments based on the exercise by third parties of contractual preferential purchase rights in properties to be acquired from Marbob (“Marbob Acquisition”).

On October 7, 2010, the Company closed the Marbob Acquisition. At closing, the Company paid approximately $1.1 billion in cash plus the unsecured senior note and common stock described above for a total purchase price of approximately $1.4 billion. The total purchase price as originally announced was reduced due to third party contractual preferential purchase rights in the Marbob properties. Certain of the third parties’ contractual preferential purchase rights became subject to litigation, as discussed below.

The Company funded the cash consideration in the Marbob Acquisition with (a) borrowings under its credit facility and (b) net proceeds of $292.7 million from a private placement of approximately 6.6 million shares of the Company’s common stock at a price of $45.30 per share that closed on October 7, 2010.

Certain of the Marbob interests in properties contained contractual preferential purchase rights by third parties if Marbob were to sell them. Marbob informed the Company of its receipt of a notice from BP America Production Company (“BP”) electing to exercise its contractual preferential purchase rights in certain of Marbob’s properties as a result of the Marbob Acquisition.

On July 20, 2010, BP announced it was selling all its assets in the Permian Basin to a subsidiary of Apache Corporation (“Apache”). Marbob and BP owned common interests in certain properties subject to contractual preferential purchase rights. BP and Apache contested Marbob’s ability to exercise its contractual preferential purchase rights in this situation. As a result, Marbob and the Company filed suit against BP and Apache seeking declaratory judgment and injunctive relief to protect Marbob’s contractual right to have the option to purchase these interests in these common properties.

On October 15, 2010, the Company and Marbob resolved the litigation with BP and Apache related to the disputed contractual preferential purchase rights. As a result of the settlement, the Company acquired a non-operated interest in substantially all of the oil and natural gas assets subject to the litigation for approximately $286 million in cash (the “Settlement Acquisition”). The Company funded the Settlement Acquisition with borrowings under its credit facility.

The results of operations of the Marbob and Settlement Acquisitions are included in the Company’s results of operations since their respective closing dates in October 2010.

9

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

The following tables represent the allocation of the total purchase price of the Marbob and Settlement Acquisitions to the acquired assets and liabilities assumed. The allocation represents the fair values assigned to each of the assets acquired and liabilities assumed:

(in thousands)	Marbob Acquisition			Settlement Acquisition
Fair value of net assets:
Proved oil and natural gas properties	$	1,014,734		$	185,337
Unproved oil and natural gas properties		334,866			101,582
Other long-term assets		20,771			-
Total assets acquired		1,370,371			286,919
Asset retirement obligations and other liabilities assumed		(7,851)			(689)
Total purchase price	$	1,362,520		$	286,230
Fair value of consideration paid for net assets:
Cash consideration	$	1,127,747		$	286,230
Marbob $150 million senior unsecured 8% note, due 2018		159,000	(a)		-
Common stock, $0.001 par value; 1,103,752 shares issued		75,773	(b)		-
Total purchase price	$	1,362,520		$	286,230

^(a)  The fair value of the $150 million 8.0% senior unsecured note due 2018 issued to Marbob, was calculated by reference to the traded market yield of Concho’s 8.625% senior unsecured notes due 2017, at September 30, 2010. On May 2, 2011, the Company paid off this note at face value with borrowings under the credit facility.

^(b)  The fair value of the Concho common stock issued to Marbob was valued at the average of the high and low price on the closing date (October 7, 2010) of $68.65 per share.

10

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Pro forma data. The following unaudited pro forma combined condensed financial data for the three and nine months ended September 30, 2010, was derived from the historical financial statements of the Company giving effect to the Marbob and Settlement Acquisitions as if they had occurred on January 1, 2010. The results of operations of the Marbob and Settlement Acquisitions are included in the Company’s results of operations for the three and nine months ended September 30, 2011.

The unaudited pro forma combined condensed financial data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had these acquisitions taken place as of the date indicated and is not intended to be a projection of future results.

(in thousands, except per share data)	Three Months Ended September 30, 2010		Nine Months Ended September 30, 2010
	(unaudited)
Operating revenues from continuing operations	$	317,751	$	829,840
Income from continuing operations	$	24,966	$	213,903
Income from continuing operations per common share:
Basic	$	0.25	$	2.18
Diluted	$	0.25	$	2.15

11

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

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 and contractual obligations. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.

The following table summarizes the Company’s asset retirement obligation activity recorded during the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Asset retirement obligations, beginning of period	$	45,195	$	22,057	$	43,326	$	22,754
Liabilities incurred from new wells		1,970		1,144		5,209		2,255
Liabilities assumed in acquisitions		-		-		148		-
Accretion expense on continuing operations		751		349		2,170		1,006
Accretion expense on discontinued operations		-		56		8		171
Disposition of wells		-		-		(412)		-
Liabilities settled upon plugging and abandoning wells		-		(522)		(686)		(819)
Revision of estimates		(430)		(626)		(2,277)		(2,909)
Asset retirement obligations, end of period	$	47,486	$	22,458	$	47,486	$	22,458

Note F. Stockholders’ equity

Public common stock offering. In December 2010, the Company issued, including the over-allotment option, in a secondary public offering 2.9 million shares of its common stock at $82.50 per share, and it received net proceeds of approximately $227.4 million. The Company used the net proceeds from this offering to repay a portion of the outstanding borrowings under its credit facility.

In February 2010, the Company issued, including the over-allotment option, in a secondary public offering 5.3 million shares of its common stock at $42.75 per share, and it received net proceeds of approximately $219.3 million. The Company used the net proceeds from this offering to repay a portion of the outstanding borrowings under its credit facility.

Private placement of common stock. In October 2010, the Company closed the private placement of its common stock, simultaneously with the closing of the Marbob Acquisition, on 6.6 million shares at a price of $45.30 per share for net proceeds of approximately $292.7 million.

Treasury stock. The restrictions on certain restricted stock awards issued to certain of the Company’s officers and key employees lapsed during the nine months ended September 30, 2011 and 2010. Immediately upon the lapse of restrictions, these officers and key employees became liable for income taxes on the value of such shares. In accordance with the Company’s 2006 Stock Incentive Plan (the “Plan”) and the applicable restricted stock award agreements, some of such officers and key employees elected to deliver shares of the Company’s common stock to the Company in exchange for cash used to satisfy such tax liability. In total, the Company had acquired 51,499 and 31,963 shares of the Company’s common stock that are held as treasury stock at September 30, 2011 and December 31, 2010, respectively.

12

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Note G. 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 6 percent of the employee’s annual salary. The Company’s contributions to the plans for the three months ended September 30, 2011 and 2010 were approximately $0.4 million and $0.3 million, respectively, and approximately $1.3 million and $0.4 million for the nine months ended September 30, 2011 and 2010, respectively.

Stock incentive plan. The Plan provides for granting stock options and restricted stock awards to employees and individuals associated with the Company. The following table shows the number of existing awards and awards available under the Plan at September 30, 2011:

	Number of Common Shares
Approved and authorized awards		5,850,000
Restricted stock grants, net of forfeitures		(1,553,697)
Stock option grants, net of forfeitures		(3,463,720)
Awards available for future grant		832,583

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 for the nine months ended September 30, 2011 is presented in the table below:

	Number of Restricted Shares		Grant Date Weighted Average Fair Value Per Share
Restricted stock:
Outstanding at December 31, 2010		820,884
Shares granted		276,291	$	95.89
Shares cancelled / forteited		(45,535)
Lapse of restrictions		(133,562)
Outstanding at September 30, 2011		918,078

13

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

The following table summarizes information about stock-based compensation for the Company’s restricted stock awards for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Grant date fair value for awards during the period and change in fair value due to modification:
Employee grants	$	13,393	$	1,916	$	16,969	$	9,257
Officer and director grants		475		215		9,525		5,290
Total	$	13,868	$	2,131	$	26,494	$	14,547
Stock-based compensation expense from restricted stock:
Employee grants	$	1,761	$	1,450	$	5,412	$	3,568
Officer and director grants		2,734		1,138		7,727		3,134
Total	$	4,495	$	2,588	$	13,139	$	6,702
Income taxes and other information:
Income tax benefit related to restricted stock	$	1,718	$	972	$	5,023	$	2,525
Deductions in current taxable income related to restricted stock	$	1,097	$	6,227	$	13,109	$	9,186

Stock option awards. A summary of the Company’s stock option awards activity under the Plan for the nine months ended September 30, 2011 is presented in the table below:

	Number of Options		Weighted Average Exercise Price
Stock options:
Outstanding at December 31, 2010		1,597,003	$	15.43
Options exercised		(651,633)	$	11.76
Outstanding at September 30, 2011		945,370	$	17.96
Vested and exercisable at end of period		782,891	$	17.19

14

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

The following table summarizes information about the Company’s vested and exercisable stock options outstanding at September 30, 2011:

			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		139,574		2.61 years	$	8.00	$	8,813
$12.00		53,510		4.01 years	$	12.00		3,165
$12.50 - $15.50		240,000		5.27 years	$	14.18		13,671
$20.00 - $23.00		276,712		6.56 years	$	21.66		13,691
$28.00 - $37.27		73,095		6.70 years	$	31.51		2,897
		782,891		5.30 years	$	17.19	$	42,237

The following table summarizes information about stock-based compensation for stock options for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Stock-based compensation expense from stock options:
Employee grants	$	20	$	39	$	65	$	125
Officer and director grants		158		525		662		2,027
Total	$	178	$	564	$	727	$	2,152
Income taxes and other information:
Income tax benefit related to stock options	$	68	$	213	$	278	$	812
Deductions in current taxable income related to stock options exercised	$	5,270	$	1,548	$	57,425	$	19,672

15

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

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 are outstanding at September 30, 2011:

	Restricted		Stock
(in thousands)	Stock		Options		Total
Remaining 2011	$	5,408	$	154	$	5,562
2012		16,004		185		16,189
2013		11,331		15		11,346
2014		5,924		-		5,924
2015		152		-		152
Total	$	38,819	$	354	$	39,173

Note H. Disclosures about fair value of financial instruments

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

Level 1:	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2:	Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company utilizes its counterparties’ valuations to assess the reasonableness of its prices and valuation techniques.
Level 3:	Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Level 3 instruments primarily include derivative instruments, such as commodity price collars, 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 our prices and valuation techniques, the Company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.

16

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis at September 30, 2011, 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		September 30,
(in thousands)	(Level 1)		(Level 2)		(Level 3)		2011
Assets:
Commodity derivative price swap contracts	$	-	$	243,594	$	-	$	243,594
		-		243,594		-		243,594
Liabilities:
Commodity derivative price swap contracts		-		(8,047)		-		(8,047)
Commodity derivative basis swap contracts		-		(1,084)		-		(1,084)
		-		(9,131)		-		(9,131)
Net derivative assets	$	-	$	234,463	$	-	$	234,463

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

(in thousands)
Balance at December 31, 2010	$	2,481
Unrealized loss		(2,481)
Realized gain		2,837
Settlements		(2,837)
Balance at September 30, 2011	$	-

17

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

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 September 30, 2011 and December 31, 2010:

	September 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
(in thousands)	Value		Value		Value		Value
Assets:
Derivative instruments	$	236,423	$	236,423	$	9,088	$	9,088
Liabilities:
Derivative instruments	$	1,960	$	1,960	$	149,422	$	149,422
Credit facility	$	293,000	$	266,430	$	613,500	$	606,042
8.625% senior notes due 2017	$	296,532	$	314,324	$	296,219	$	322,879
8.0% senior note due 2018	$	-	$	-	$	158,802	$	162,772
7.0% senior notes due 2021	$	600,000	$	597,000	$	600,000	$	615,000
6.5% senior notes due 2022	$	600,000	$	591,000	$	-	$	-

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

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

Senior notes. The fair values of the Company’s 8.625%, 7.0%, and 6.5% senior notes are based on quoted market prices. The fair value of the $150 million 8.0% senior note issued to Marbob at December 31, 2010, was based on a risk-adjusted quoted market price of similar publicly-traded debt securities. On May 2, 2011, the Company paid off the 8.0% unsecured senior note at face value with borrowings under the credit facility.

18

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Derivative instruments. The fair value of the Company’s derivative instruments are estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table (i) summarizes the valuation of each of the Company’s financial instruments by required pricing levels and (ii) summarizes the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at September 30, 2011 and December 31, 2010:

	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 September 30, 2011
Assets (a)
Current:(b)
Commodity derivative price swap contracts	$	-	$	150,052	$	-	$	150,052
		-		150,052		-		150,052
Noncurrent:(c)
Commodity derivative price swap contracts		-		93,542		-		93,542
		-		93,542		-		93,542
Liabilities (a)
Current:(b)
Commodity derivative price swap contracts		-		(5,256)		-		(5,256)
Commodity derivative basis swap contracts		-		(1,084)		-		(1,084)
		-		(6,340)		-		(6,340)
Noncurrent:(c)
Commodity derivative price swap contracts		-		(2,791)		-		(2,791)
		-		(2,791)		-		(2,791)
Net derivative assets	$	-	$	234,463	$	-	$	234,463
(b) Total current derivative assets, gross basis							$	143,712
(c) Total noncurrent derivative assets, gross basis								90,751
Net derivative assets							$	234,463

19

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

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, 2010
Assets (a)
Current:(b)
Commodity derivative price swap contracts	$	-	$	32,877	$	-	$	32,877
Commodity derivative price collar contracts		-		-		2,481		2,481
		-		32,877		2,481		35,358
Noncurrent:(c)
Commodity derivative price swap contracts		-		16,642		-		16,642
		-		16,642		-		16,642
Liabilities (a)
Current:(b)
Commodity derivative price swap contracts		-		(118,131)		-		(118,131)
Commodity derivative basis swap contracts		-		(3,552)		-		(3,552)
Interest rate derivative swap contracts		-		(4,595)		-		(4,595)
		-		(126,278)		-		(126,278)
Noncurrent:(c)
Commodity derivative price swap contracts		-		(64,897)		-		(64,897)
Interest rate derivative swap contracts		-		(1,159)		-		(1,159)
		-		(66,056)		-		(66,056)
Net derivative assets (liabilities)	$	-	$	(142,815)	$	2,481	$	(140,334)
(b) Total current derivative liabilities, gross basis							$	(90,920)
(c) Total noncurrent derivative liabilities, gross basis								(49,414)
Net derivative liabilities							$	(140,334)

(a) The fair value of derivative instruments reported in the Company’s consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table reports the net basis derivative fair values as reported in the consolidated balance sheets at September 30, 2011 and December 31, 2010:

(in thousands)	September 30, 2011		December 31, 2010
Consolidated Balance Sheet Classification:
Current derivative contracts:
Assets	$	145,671	$	6,855
Liabilities		(1,960)		(97,775)
Net current	$	143,711	$	(90,920)
Noncurrent derivative contracts:
Assets	$	90,752	$	2,233
Liabilities		-		(51,647)
Net noncurrent	$	90,752	$	(49,414)

20

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

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 judgment, including estimation of the proved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs.

The Company periodically reviews its proved oil and natural gas properties for impairment. Impairment expense is caused primarily due to declines in commodity prices and well performance. The 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 nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Carrying amount	$	-	$	4,083	$	77	$	17,859
Less: estimated fair value		-		(2,161)		(1)		(8,625)
Impairment of long-lived assets	$	-	$	1,922	$	76	$	9,234

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 judgment 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.

21

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

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 September 30, 2011:
Impairment of long-lived assets	$	-	$	-	$	-	$	-
Asset retirement obligations incurred in current period		-		-		1,970
Three Months Ended September 30, 2010:
Impairment of long-lived assets	$	-	$	-	$	2,161	$	1,922
Asset retirement obligations incurred in current period		-		-		1,144
Nine Months Ended September 30, 2011:
Impairment of long-lived assets	$	-	$	-	$	1	$	76
Asset retirement obligations incurred in current period		-		-		5,357
Nine Months Ended September 30, 2010:
Impairment of long-lived assets	$	-	$	-	$	8,625	$	9,234
Asset retirement obligations incurred in current period		-		-		2,255

Note I. Derivative financial instruments

The Company uses derivative financial contracts to manage 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. Interest rate hedges are used to mitigate the cash flow risk associated with rising interest rates. The Company does not enter into derivative financial instruments for speculative or trading purposes. The Company also may enter into physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated financial statements.

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

22

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

New commodity derivative contracts in the first nine months of 2011. During the nine months ended September 30, 2011, the Company entered into additional commodity derivative contracts to hedge a portion of its estimated future production. The following table summarizes information about these additional commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Aggregate Volume		Index Price (a)		Contract Period
Oil (volumes in Bbls):
Price swap		115,000	$	96.65		03/01/11 - 11/30/11
Price swap		200,000	$	97.20		03/01/11 - 12/31/11
Price swap		190,000	$	111.41		05/01/11 - 07/31/11
Price swap		736,000	$	110.21		05/01/11 - 12/31/11
Price swap		66,000	$	111.80		08/01/11 - 11/30/11
Price swap		535,000	$	100.66		10/01/11 - 12/31/11
Price swap		45,000	$	99.35		01/01/12 - 03/31/12
Price swap		176,000	$	110.34		01/01/12 - 11/30/12
Price swap		2,244,000	$	103.83		01/01/12 - 12/31/12
Price swap		555,000	$	99.00		07/01/12 - 12/31/12
Price swap		210,000	$	103.65		01/01/13 - 06/30/13
Price swap		3,444,000	$	101.25		01/01/13 - 12/31/13

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

23

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Commodity derivative contracts at September 30, 2011. The following table sets forth the Company’s outstanding commodity derivative contracts at September 30, 2011. When aggregating multiple contracts, the weighted average contract price is disclosed.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
Oil Swaps: (a)
2011:
Volume (Bbl)								3,133,436		3,133,436
Price per Bbl								$89.00		$89.00
2012:
Volume (Bbl)		2,811,500		2,609,500		2,455,500		2,324,500		10,201,000
Price per Bbl		$93.80		$93.55		$95.13		$95.10		$94.35
2013:
Volume (Bbl)		1,311,000		1,311,000		1,206,000		1,206,000		5,034,000
Price per Bbl		$96.53		$96.53		$95.91		$95.91		$96.23
2014:
Volume (Bbl)		312,000		312,000		312,000		312,000		1,248,000
Price per Bbl		$83.94		$83.94		$83.94		$83.94		$83.94
2015:
Volume (Bbl)		300,000		300,000		-		-		600,000
Price per Bbl		$84.50		$84.50		$    -		$    -		$84.50
Natural Gas Swaps: (b)
2011:
Volume (MMBtu)								3,069,000		3,069,000
Price per MMBtu								$6.62		$6.62
2012:
Volume (MMBtu)		75,000		75,000		75,000		75,000		300,000
Price per MMBtu		$6.54		$6.54		$6.54		$6.54		$6.54
Natural Gas Basis Swaps: (c)
2011:
Volume (MMBtu)								1,800,000		1,800,000
Price per MMBtu								$0.76		$0.76

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

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

(c) The basis differential between the El Paso Permian delivery point and NYMEX-Henry Hub delivery point.

24

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Interest rate derivative contracts. The Company previously had interest rate swaps that fixed the LIBOR interest rate 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 amounts that may be outstanding under its credit facility, the Company terminated its interest rate swaps for approximately $5.0 million. See Note J 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 nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Gain (loss) on derivatives not designated as hedges:
Cash (payments on) receipts from derivatives not designated as hedges:
Commodity derivatives:
Oil	$	(8,051)	$	1,034	$	(88,679)	$	(11,951)
Natural gas		6,263		4,258		17,468		10,378
Interest rate derivatives		-		(1,224)		(6,624)		(3,658)
Mark-to-market gain (loss):
Commodity derivatives:
Oil		390,327		(79,815)		381,385		40,926
Natural gas		(3,317)		10,300		(12,342)		30,978
Interest rate derivatives		-		(660)		5,754		(4,444)
Total gain (loss) on derivatives not designated as hedges	$	385,222	$	(66,107)	$	296,962	$	62,229

All of the Company’s derivative contracts at September 30, 2011 are expected to settle by June 30, 2015.

Note J. Debt

The Company’s debt consisted of the following at September 30, 2011 and December 31, 2010:

(in thousands)	September 30, 2011		December 31, 2010
Credit facility	$	293,000	$	613,500
8.625% unsecured senior notes due 2017		300,000		300,000
8.0% unsecured senior note due 2018		-		150,000
7.0% unsecured senior notes due 2021		600,000		600,000
6.5% unsecured senior notes due 2022		600,000		-
Unamortized original issue (discount) premium, net		(3,468)		5,021
Total long-term debt	$	1,789,532	$	1,668,521

25

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Credit facility. The Company’s credit facility, as amended (the “Credit Facility”), has a maturity date of April 25, 2016. The Company’s borrowing base is $2.5 billion until the next scheduled borrowing base redetermination in April 2012, and commitments from the Company’s bank group total $2.0 billion. Between scheduled borrowing base redeterminations, the Company and, if requested by 66 2/3 percent of the lenders, the lenders, may each request one special redetermination. At September 30, 2011, the Company had no letters of credit outstanding under the Credit Facility.

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 September 30, 2011) 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. The Company pays 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.

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 the equity interests in such subsidiaries have been pledged to secure borrowings under the Credit Facility.

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

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

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

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

• restrictions on the payment of cash dividends.

At September 30, 2011, the Company was in compliance with all of the covenants under the Credit Facility.

8.625% unsecured 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 beginning April 1, 2010. The 2017 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries.

7.0% unsecured senior notes. In December 2010, the Company issued $600 million aggregate principal amount of 7.0% senior notes due 2021 at 100 percent of 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% unsecured senior notes. In May 2011, the Company issued $600 million aggregate principal amount of 6.5% senior notes due 2022 at 100 percent of par (the “2022 Senior Notes”). The 2022 Senior Notes mature on January 15, 2022, and interest is paid in arrears semi-annually on January 15 and July 15. The 2022 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries.

26

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

8.0% unsecured senior note. As part of the consideration for the Marbob Acquisition, the Company issued a $150 million 8.0% unsecured senior note due 2018 to Marbob. On May 2, 2011, the Company paid off the 8.0% unsecured senior note at face value with borrowings under the credit facility and reduced interest expense by approximately $8.5 million, as a result of the write-off of the unamortized premium.

The following table summarizes future interest expense from the net original issue discount at September 30, 2011:

(in thousands)
Remaining 2011	$	109
2012		462
2013		507
2014		557
2015		612
Thereafter		1,221
Total	$	3,468

Principal maturities of debt. The following table summarizes the principal maturities of long-term debt outstanding at September 30, 2011:

(in thousands)
2011	$	-
2012		-
2013		-
2014		-
2015		-
Thereafter		1,793,000
Total	$	1,793,000

27

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Interest expense. The following amounts have been incurred and charged to interest expense for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Cash payments for interest	$	28,683	$	5,983	$	60,825	$	27,746
Amortization of net original issue discount (premium)		106		97		24		284
Amortization of deferred loan origination costs		2,644		1,227		8,997		3,431
Write-off of original issue premium		-		-		(8,513)		-
Net changes in accruals		1,448		4,792		22,941		2,951
Interest costs incurred		32,881		12,099		84,274		34,412
Less: capitalized interest		-		(63)		(73)		(119)
Total interest expense	$	32,881	$	12,036	$	84,201	$	34,293

Note K. Commitments and contingencies

Severance agreements. The Company has entered into severance and change in control agreements with all of its officers. The current annual salaries for the Company’s officers covered under such agreements total approximately $3.6 million.

Indemnification. 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.

Daywork commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future, including agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments in the periods in which well capital is incurred or rig services are provided. The following table summarizes the Company’s future drilling commitments at September 30, 2011:

	Payments Due By Period
(in thousands)	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than         5 years
Daywork drilling contracts with related parties (a)	$	1,395	$	1,395	$	-	$	-	$	-
Other daywork drilling contracts		5,607		5,607		-		-		-
Total contractual drilling commitments	$	7,002	$	7,002	$	-	$	-	$	-

^(a) Consists of daywork drilling contracts with a company in which one of the Company’s employees owns a 3 percent interest.

28

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Operating leases. The Company leases vehicles, equipment and office facilities under non-cancellable operating leases. Lease payments associated with these operating leases for the three months ended September 30, 2011 and 2010 were approximately $0.9 million and $0.3 million, respectively, and approximately $2.6 million and $1.4 million for the nine months ended September 30, 2011 and 2010, respectively.

Future minimum lease commitments under non-cancellable operating leases at September 30, 2011 were as follows:

(in thousands)
Remaining 2011	$	1,047
2012		3,808
2013		3,223
2014		2,563
2015		2,075
Thereafter		1,480
Total	$	14,196

Note L. Income taxes

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

The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net operating loss carryforwards (“NOLs”), if any, and other deferred tax attributes in the United States, state, and local tax jurisdictions will be utilized prior to their expiration. At September 30, 2011 and December 31, 2010, the Company had no valuation allowances related to its deferred tax assets.

At September 30, 2011, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2008 through 2010 remain subject to examination by the major tax jurisdictions.

Income tax provision. The Company’s income tax provision and amounts separately allocated were attributable to the following items for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Income from continuing operations	$	221,199	$	7,392	$	334,000	$	118,375
Income from discontinued operations		-		2,690		56,529		6,391
Changes in stockholders’ equity:
Excess tax benefits related to stock-based compensation		(2,105)		(2,265)		(23,222)		(8,968)
	$	219,094	$	7,817	$	367,307	$	115,798

29

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

The Company’s income tax provision attributable to income from continuing operations consisted of the following for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Current:
U.S. federal	$	9,826	$	(878)	$	19,378	$	8,875
U.S. state and local		1,141		525		2,423		2,239
Total current income tax provision		10,967		(353)		21,801		11,114
Deferred:
U.S. federal		182,698		7,216		271,297		96,265
U.S. state and local		27,534		529		40,902		10,996
Total deferred income tax provision		210,232		7,745		312,199		107,261
Total income tax provision attributable to income from continuing operations	$	221,199	$	7,392	$	334,000	$	118,375

The reconciliation between the income tax expense computed by multiplying pre-tax 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 September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Income at U.S. federal statutory rate	$	202,091	$	8,247	$	305,821	$	111,883
State income taxes, net of federal tax effect		18,592		632		28,115		8,549
Statutory depletion		(110)		(55)		(296)		(232)
Nondeductible expense & other		626		(1,432)		360		(1,825)
Income tax expense	$	221,199	$	7,392	$	334,000	$	118,375
Effective tax rate		38.3%		31.4%		38.2%		37.0%

The Company’s income tax provision attributable to income from discontinued operations consisted of the following for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Current:
U.S. federal	$	-	$	896	$	(1,192)	$	3,649
U.S. state and local		-		4		4		15
Total current income tax provision (benefit)		-		900		(1,188)		3,664
Deferred:
U.S. federal		-		1,499		50,373		2,042
U.S. state and local		-		291		7,344		685
Total deferred income tax provision		-		1,790		57,717		2,727
Total income tax provision attributable to income from discontinued operations	$	-	$	2,690	$	56,529	$	6,391

30

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Note M. 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 and receivables included in the consolidated balance sheets for the periods presented:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Charges incurred with Chase Oil and affiliates (a)			$	11,395			$	26,902
Working interests owned by employees: (b)
Revenues distributed to employees	$	51	$	49	$	240	$	220
Joint interest payments received from employees	$	85	$	293	$	448	$	868
Acquisition of oil and natural gas interests from an employee	$	-	$	363	$	-	$	363
Overriding royalty interests paid to Chase Oil affiliates (c)			$	412			$	1,458
Royalty interests paid to a director of the Company (d)	$	37	$	42	$	99	$	121
Amounts paid under consulting agreement with a director (e)	$	60	$	64	$	180	$	194
Amounts paid under daywork drilling contracts (f)	$	4,124	$	-	$	11,452	$	-

(in thousands)	September 30, 2011		December 31, 2010
Amounts included in accounts receivable - related parties:
Chase Oil and affiliates (a)			$	115
Working interests owned by employees (b)	$	103	$	54
Amounts included in accounts payable - related parties:
Chase Oil and affiliates (a)			$	771
Working interests owned by employees (b)	$	11	$	8
Overriding royalty interests of Chase Oil affiliates (c)			$	407
Royalty interests of a director of the Company (d)	$	14	$	11

(a) The Company incurred charges for services rendered in the ordinary course of business from Chase Oil Corporation (“Chase Oil”) and its affiliates, including a drilling contractor, an oilfield services company, a supply company, a drilling fluids supply company, a pipe and tubing supplier, a fixed base operator of aircraft services and a software company. The Company also operates oil and natural gas wells in which Chase Oil owns a working interest. As such, the Company has outstanding receivables related to these oil and natural gas properties from time to time. The tables above summarize the charges incurred as well as outstanding receivables and payables. At January 1, 2011, Chase Oil was no longer considered a related party due to the decrease in their ownership percentage.

31

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

(b) The Company purchased oil and natural gas properties from third parties in which employees of the Company owned a working interest. The tables above summarize the Company’s activities with these employees. During the three and nine months ended September 30, 2010, the Company acquired oil and natural gas interests from an employee of the Company.

(c) Certain persons affiliated with Chase Oil own overriding royalty interests in certain of the Company’s properties. The tables above summarize the amounts paid attributable to such interests and amounts due at period end. At January 1, 2011, Chase Oil was no longer considered a related party due to the decrease in their ownership percentage.

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

(e) In June 2009, the Company entered into a consulting agreement (the “Consulting Agreement”) with Steven L. 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.

(f) The Company incurred charges for services rendered in the ordinary course of business from a drilling contractor in which one of the Company’s employees owns a 3 percent interest.

32

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Note N. Discontinued operations

In March 2011, the Company sold its Bakken assets for cash consideration of approximately $195.9 million. The Company recognized a gain on the disposition of assets in discontinued operations of approximately $142.0 million.

In December 2010, the Company sold certain of its non-core Permian Basin assets for cash consideration of approximately $103.3 million. The Company recorded a gain on the disposition of assets in discontinued operations of approximately $29.1 million.

The Company has reflected the results of operations of these two divestitures as discontinued operations, rather than as a component of continuing operations. The following table represents the components of the Company’s discontinued operations for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Operating revenues:
Oil sales	$	-	$	13,376	$	9,456	$	38,448
Natural gas sales		-		1,329		68		5,479
Total operating revenues		-		14,705		9,524		43,927
Operating costs and expenses:
Oil and natural gas production		-		3,310		1,642		10,686
Exploration and abandonments		-		8		-		150
Depreciation, depletion and amortization (a)		-		4,276		2,107		12,450
Accretion of discount on asset retirement obligations (a)		-		56		8		171
Impairments of long-lived assets (a)		-		-		-		3,567
General and administrative (b)		-		(240)		-		(683)
Total operating costs and expenses		-		7,410		3,757		26,341
Income from operations		-		7,295		5,767		17,586
Other income (expense):
Gain on disposition of assets, net (a)		-		-		141,950		-
Income from discontinued operations before income taxes		-		7,295		147,717		17,586
Income tax benefit (expense):
Current		-		(900)		1,188		(3,664)
Deferred (a)		-		(1,790)		(57,717)		(2,727)
Income from discontinued operations, net of tax	$	-	$	4,605	$	91,188	$	11,195

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

(b) Represents the fees received from third-parties for operating oil and natural gas properties that were sold. The Company reflects these fees as a reduction of general and administrative expenses.

33

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Note O. 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 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 common 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 nine months ended September 30, 2011 and 2010:

	Three Months Ended         September 30,				Nine Months Ended         September 30,
(in thousands)	2011		2010		2011		2010
Weighted average common shares outstanding:
Basic		102,733		91,182		102,517		90,361
Dilutive common stock options		503		845		605		892
Dilutive restricted stock		460		413		491		378
Diluted		103,696		92,440		103,613		91,631

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 September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Number of antidilutive common shares:
Anti-dilutive common stock options		-		-		-		1
Anti-dilutive restricted stock		60		19		36		9

34

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Note P. Other current liabilities

The following table provides the components of the Company’s other current liabilities at September 30, 2011 and December 31, 2010:

(in thousands)	September 30, 2011		December 31, 2010
Other current liabilities:
Accrued production costs	$	45,068	$	31,149
Payroll related matters		9,303		13,790
Accrued interest		38,435		15,494
Asset retirement obligations		6,330		7,378
Settlements due on derivative instruments		308		7,371
Other		9,307		8,093
Other current liabilities	$	108,751	$	83,275

Note Q. Subsidiary guarantors

All of the Company’s wholly-owned subsidiaries have fully and unconditionally guaranteed the senior notes of the Company (see Note J). In accordance with practices accepted by the SEC, the Company has prepared the following Condensed Consolidating Financial Statements in order to quantify the assets and liabilities, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following Condensed Consolidating Balance Sheets at September 30, 2011 and December 31, 2010, Condensed Consolidating Statements of Operations for the three and nine months ended September 30, 2011 and 2010 and Condensed Consolidating Statements of Cash Flows for the nine months ended September 30, 2011 and 2010 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 parent company.

35

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Condensed Consolidating Balance Sheet

September 30, 2011

(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
ASSETS
Accounts receivable - related parties	$	4,707,001	$	195,223	$	(4,902,121)	$	103
Other current assets		147,095		399,898		-		546,993
Oil and natural gas properties, net		-		5,691,826		-		5,691,826
Property and equipment, net		-		53,791		-		53,791
Investment in subsidiaries		2,173,528		-		(2,173,528)		-
Other long-term assets		159,049		71,024		-		230,073
Total assets	$	7,186,673	$	6,411,762	$	(7,075,649)	$	6,522,786
LIABILITIES AND EQUITY
Accounts payable - related parties	$	1,271,527	$	3,630,619	$	(4,902,121)	$	25
Other current liabilities		95,631		566,030		-		661,661
Other long-term liabilities		972,344		41,585		-		1,013,929
Long-term debt		1,789,532		-		-		1,789,532
Equity		3,057,639		2,173,528		(2,173,528)		3,057,639
Total liabilities and equity	$	7,186,673	$	6,411,762	$	(7,075,649)	$	6,522,786

Condensed Consolidating Balance Sheet

December 31, 2010

(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
ASSETS
Accounts receivable - related parties	$	5,532,317	$	534,447	$	(6,066,595)	$	169
Other current assets		51,084		279,380		-		330,464
Oil and natural gas properties, net		-		4,885,740		-		4,885,740
Property and equipment, net		-		28,047		-		28,047
Investment in subsidiaries		1,363,908		-		(1,363,908)		-
Other long-term assets		55,061		69,013		-		124,074
Total assets	$	7,002,370	$	5,796,627	$	(7,430,503)	$	5,368,494
LIABILITIES AND EQUITY
Accounts payable - related parties	$	2,061,777	$	4,006,015	$	(6,066,595)	$	1,197
Other current liabilities		115,662		390,130		-		505,792
Other long-term liabilities		772,536		36,574		-		809,110
Long-term debt		1,668,521		-		-		1,668,521
Equity		2,383,874		1,363,908		(1,363,908)		2,383,874
Total liabilities and equity	$	7,002,370	$	5,796,627	$	(7,430,503)	$	5,368,494

36

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2011

(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
Total operating revenues	$	-	$	454,468	$	-	$	454,468
Total operating costs and expenses		383,660		(225,340)		-		158,320
Income from continuing operations		383,660		229,128		-		612,788
Interest expense		(32,881)		-		-		(32,881)
Other, net		226,625		(2,503)		(226,625)		(2,503)
Income from continuing operations before income taxes		577,404		226,625		(226,625)		577,404
Income tax expense		(221,199)		-		-		(221,199)
Net income	$	356,205	$	226,625	$	(226,625)	$	356,205

Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2010

(in thousands)	Parent Issuer		Subsidiary Guarantors		Consolidating Entries		Total
Total operating revenues	$	-	$	225,791	$	-	$	225,791
Total operating costs and expenses		(64,846)		(121,826)		-		(186,672)
Income (loss) from continuing operations		(64,846)		103,965		-		39,119
Interest expense		(12,036)		-		-		(12,036)
Other, net		107,739		(3,521)		(107,739)		(3,521)
Income from continuing operations before income taxes		30,857		100,444		(107,739)		23,562
Income tax expense		(7,392)		-		-		(7,392)
Income from continuing operations		23,465		100,444		(107,739)		16,170
Income (loss) from discontinued operations, net of tax		(2,690)		7,295		-		4,605
Net income	$	20,775	$	107,739	$	(107,739)	$	20,775

37

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2011

	Parent		Subsidiary		Consolidating
(in thousands)	Issuer		Guarantors		Entries		Total
Total operating revenues	$	-	$	1,261,540	$	-	$	1,261,540
Total operating costs and expenses		295,972		(594,947)		-		(298,975)
Income from continuing operations		295,972		666,593		-		962,565
Interest expense		(84,201)		-		-		(84,201)
Other, net		809,720		(4,690)		(809,620)		(4,590)
Income from continuing operations before income taxes		1,021,491		661,903		(809,620)		873,774
Income tax expense		(334,000)		-		-		(334,000)
Income from continuing operations		687,491		661,903		(809,620)		539,774
Income (loss) from discontinued operations, net of tax		(56,529)		147,717		-		91,188
Net income	$	630,962	$	809,620	$	(809,620)	$	630,962

Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2010

	Parent		Subsidiary		Consolidating
(in thousands)	Issuer		Guarantors		Entries		Total
Total operating revenues	$	-	$	624,279	$	-	$	624,279
Total operating costs and expenses		60,209		(326,631)		-		(266,422)
Income from continuing operations		60,209		297,648		-		357,857
Interest expense		(34,293)		-		-		(34,293)
Other, net		311,336		(3,898)		(311,336)		(3,898)
Income from continuing operations before income taxes		337,252		293,750		(311,336)		319,666
Income tax expense		(118,375)		-		-		(118,375)
Income from continuing operations		218,877		293,750		(311,336)		201,291
Income (loss) from discontinued operations, net of tax		(6,391)		17,586		-		11,195
Net income	$	212,486	$	311,336	$	(311,336)	$	212,486

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2011

	Parent		Subsidiary		Consolidating
(in thousands)	Issuer		Guarantors		Entries		Total
Net cash flows provided by (used in) operating activities	$	(60,598)	$	839,584	$	-	$	778,986
Net cash flows used in investing activities		(73,419)		(884,326)		-		(957,745)
Net cash flows provided by financing activities		133,971		44,578		-		178,549
Net decrease in cash and cash equivalents		(46)		(164)		-		(210)
Cash and cash equivalents at beginning of period		46		338		-		384
Cash and cash equivalents at end of period	$	-	$	174	$	-	$	174

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2010

	Parent		Subsidiary		Consolidating
(in thousands)	Issuer		Guarantors		Entries		Total
Net cash flows provided by (used in) operating activities	$	(68,526)	$	471,282	$	-	$	402,756
Net cash flows used in investing activities		(3,539)		(509,285)		-		(512,824)
Net cash flows provided by financing activities		72,055		35,136		-		107,191
Net decrease in cash and cash equivalents		(10)		(2,867)		-		(2,877)
Cash and cash equivalents at beginning of period		48		3,186		-		3,234
Cash and cash equivalents at end of period	$	38	$	319	$	-	$	357

39

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Note R. Subsequent events

New commodity derivative contracts. In October 2011, the Company entered into the following commodity derivative contracts to hedge additional amounts of its estimated future production:

	Aggregate		Index		Contract
	Volume		Price (a)		Period
Oil (volumes in Bbls):
Price swap		1,080,000		$89.23	01/01/12 - 12/31/12
Price swap		27,000		$89.10	07/01/12 - 09/30/12
Price swap		2,400,000		$90.21	01/01/13 - 12/31/13

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

Delaware Basin acquisitions. The Company has acquired or entered into definitive agreements to acquire acreage in the Delaware Basin for approximately $330 million, subject to normal post-closing adjustments. These acquisitions are expected to close in the fourth quarter of 2011 and will be funded with borrowings under the Credit Facility.

At September 30, 2011, the Company had paid a $6.2 million performance guaranty deposit related to one of the acquisitions, which would be relinquished upon nonperformance or reduce the funding of the purchase price at closing.

40

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2011

Unaudited

Note S. Supplementary information

Capitalized costs

		000000000000		000000000000
	September 30,		December 31,
(in thousands)	2011		2010
Oil and natural gas properties:
Proved	$	5,934,879	$	4,982,316
Unproved		752,208		633,933
Less: accumulated depletion and depreciation		(995,261)		(730,509)
Net capitalized costs for oil and natural gas properties	$	5,691,826	$	4,885,740

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

		000000000000		000000000000		000000000000		000000000000
	Three Months Ended				Six Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Property acquisition costs:
Proved	$	-	$	3,762	$	69,148	$	17,501
Unproved		42,432		10,874		117,772		31,903
Exploration		138,170		74,740		410,089		136,673
Development		233,062		88,310		567,547		334,222
Total costs incurred for oil and natural gas properties	$	413,664	$	177,686	$	1,164,556	$	520,299

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

		000000000000		000000000000		000000000000		000000000000
	Three Months Ended				Six Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Proved property acquisition costs	$	-	$	-	$	148	$	-
Exploration costs		198		321		838		573
Development costs		1,342		197		2,094		(1,227)
Total	$	1,540	$	518	$	3,080	$	(654)

41

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

The following discussion is intended to assist you in understanding our business and results of operations together with our financial condition. This section should be read in conjunction with our historical consolidated financial statements and notes.

In March 2011, we sold our Bakken assets for cash consideration of approximately $195.9 million and recognized a gain on the disposition of assets (included in discontinued operations) of approximately $142.0 million as discussed in Note N of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).” For the three months ended March 31, 2011, these assets produced an average of 1,369 barrels of oil equivalents (“Boe”) per day, of which approximately 95 percent was oil.

In December 2010, we sold certain of our non-core Permian Basin assets for cash consideration of approximately $103.3 million and recognized a gain of approximately $29.1 million as discussed in Note N of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).” For 2010, these assets produced an average of 1,393 Boe per day, of which approximately 46 percent was oil.

In October 2010, we closed the Marbob and Settlement Acquisitions, as discussed in Note D of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).” The results of these acquisitions are included in our results of operations for periods after their respective closing dates in October 2010. As a result of our acquisitions and dispositions, many comparisons between periods will be difficult.

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 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, and (iii) Texas Permian, where we primarily target the Wolfberry, a term applied to the combined Wolfcamp and Spraberry horizons. Oil comprised 65 percent of our 323.5 million barrels of oil equivalents (“MMBoe”) of estimated proved reserves at December 31, 2010 and 62 percent of our 17.1 MMBoe of production for the nine months ended September 30, 2011. We seek to operate the wells in which we own an interest, and our operated wells accounted for 92.3 percent of our proved developed producing PV-10 and 69.8 percent of our 5,196 gross wells at December 31, 2010. 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 nine months ended September 30, 2011, as compared to the nine months ended September 30, 2010, included the following:

• Net income was $631.0 million ($6.09 per diluted share) for the first nine months of 2011, as compared to $212.5 million ($2.32 per diluted share) during the first nine months of 2010. The increase in earnings is primarily due to:

¡ a $637.3 million increase in oil and natural gas revenues primarily as a result of a 73 percent increase in production from continuing operations due to (i) the Marbob and Settlement Acquisitions and (ii) new wells that were successfully drilled and completed in 2010 and 2011;

¡ a $297.0 million net gain on derivatives not designated as hedges during the first nine months of 2011, as compared to a $62.2 million net gain on derivatives not designated as hedges during the first nine months of 2010, primarily the result of decreases in forward-looking commodity prices in the respective periods;

¡ a $142.0 million pre-tax gain from the divestiture of our Bakken assets in the first quarter of 2011, included in discontinued operations; partially offset by,

42

Ø a $105.8 million increase in oil and natural gas production costs during the first nine months of 2011, due in part to the increase in (i) the number of new wells that were successfully drilled and completed in 2010 and 2011, (ii) the Marbob and Settlement Acquisitions and (iii) oil and natural gas revenues in 2011, which directly increased our oil and natural gas production taxes;

Ø a $147.5 million increase in depreciation, depletion and amortization during the first nine months of 2011, primarily due to capitalized costs associated with new wells that were successfully drilled and completed in 2010 and 2011 and the Marbob and Settlement Acquisitions, offset in part by the increase in the oil and natural gas prices between the periods utilized to determine proved reserves; and

Ø a $49.9 million increase in interest expense due to (i) increased average debt levels during 2011 compared to 2010, primarily related to the Marbob and Settlement Acquisitions, and (ii) an increase in our overall interest rate, primarily from the higher interest rates on our various issues of senior notes as compared to interest rates on borrowings on our credit facility.

• Average daily sales volumes from continuing operations increased by 73 percent, from 35,872 Boe per day during the first nine months of 2010 to 62,231 Boe per day during the first nine months of 2011. The increase is primarily attributable to (i) the Marbob and Settlement Acquisitions and (ii) our successful drilling efforts during 2010 and 2011, partially offset by interruptions in production during the first quarter of 2011.

• Long-term debt increased by $121.0 million from December 31, 2010 to September 30, 2011.

• At September 30, 2011, our availability under our credit facility was approximately $1.7 billion based on commitments from our bank group of $2.0 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:

• 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;

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

n the United States economy,

n weather conditions, and

n liquefied natural gas deliveries to the United States; and

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

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 continue to use derivative financial instruments to economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commodity hedge position at September 30, 2011.

43

Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, oil prices were higher during the comparable periods of 2011 measured against 2010, while natural gas prices were relatively flat. The following table sets forth the average NYMEX oil and natural gas prices for the three and nine months ended September 30, 2011 and 2010, as well as the high and low NYMEX prices for the same periods:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
Average NYMEX prices:
Oil (Bbl)	$	89.59	$	76.09	$	95.46	$	77.60
Natural gas (MMBtu)	$	4.06	$	4.24	$	4.21	$	4.54
High and Low NYMEX prices:
Oil (Bbl):
High	$	99.87	$	82.55	$	113.93	$	86.84
Low	$	79.20	$	71.63	$	79.20	$	68.01
Natural gas (MMBtu):
High	$	4.55	$	4.92	$	4.85	$	6.01
Low	$	3.67	$	3.65	$	3.67	$	3.65

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $93.96 and $75.67 per Bbl and $3.93 and $3.48 per MMBtu, respectively, during the period from September 30, 2011 to November 1, 2011. At November 1, 2011, the NYMEX oil price and NYMEX natural gas price were $92.19 per Bbl and $3.78 per MMBtu, respectively.

Recent Events

Delaware Basin acquisitions. We have acquired or entered into definitive agreements to acquire acreage in the Delaware Basin for approximately $330 million, subject to normal post-closing adjustments. The acreage is complementary to our existing Delaware Basin position and increases our related inventory. These acquisitions are expected to close in the fourth quarter of 2011 and will be funded with borrowings under our credit facility.

Credit facility amendment. In 2011, we amended our credit facility to (i) extend the maturity date by approximately three years to April 2016, (ii) increase the borrowing base from $2.0 billion to $2.5 billion, but keep our commitments from our bank group at $2.0 billion and (iii) provide us with the ability to issue up to an additional $1.0 billion in senior notes with no adjustment to our borrowing base if the notes are issued prior to November 2012. We paid our bank group approximately $11.5 million associated with these amendments. At September 30, 2011, we had borrowings outstanding under our credit facility of approximately $0.3 billion, and our availability under our credit facility was approximately $1.7 billion.

Senior notes issuance. In May 2011, we issued $600 million in principal amount of 6.5% unsecured senior notes due 2022 and we received net proceeds of approximately $587.1 million. We used the net proceeds to repay a portion of the borrowings under our credit facility, which increased our liquidity for future activities.

Bakken divestiture. In March 2011, we sold our Bakken assets for cash consideration of approximately $195.9 million and recognized a gain on the disposition of assets (included in discontinued operations) of approximately $142.0 million. For 2011, these assets produced an average of 1,369 Boe per day, of which approximately 95 percent was oil. The proved reserves of these assets were approximately 8.2 MMBoe at closing.

2012 capital budget. In November 2011, we announced our 2012 capital budget of approximately $1.3 billion, which we expect can be funded within our cash flow, based on current commodity prices and capital costs. Cost inflation has been experienced industry-wide and particularly in the Permian Basin due to the increased activity levels. As our size and financial flexibility have grown, we now take a longer-term view on spending within our cash flow, and our spending during any specific period may exceed our cash flow for that period. However, our capital budget is largely discretionary, and if we experience sustained oil and natural gas

44

prices significantly below the current levels or substantial increases in our costs, we may reduce our capital spending program to be substantially within our cash flow.

The following table summarizes our 2012 capital budget, which does not include acquisitions other than customary purchase of leasehold acreage:

(in millions)	2012 Capital Budget
Core Operating Areas:
New Mexico Shelf	$	495
Delaware Basin		374
Texas Permian		262
Acquisition of leasehold acreage, geological and geophysical, exploratory costs and other		113
Facilities and other capital in our core operating areas		50
Total	$	1,294

2011 planned capital expenditures. For 2011, we expect capital expenditures to total approximately $1.35 billion, excluding the costs of acquisitions other than customary leasehold purchases of acreage. Based on current commodity prices and capital costs, we believe our 2011 planned capital expenditures, excluding the effects of acquisitions, will exceed our 2011 cash flow, and we expect to fund any such shortfall with borrowings under our credit facility.

The following summarizes our 2011 planned capital expenditures, which do not include acquisitions other than the customary purchase of leasehold acreage:

(in millions)	2011 Planned Capital Expenditures
Core Operating Areas:
New Mexico Shelf	$	644
Delaware Basin		252
Texas Permian		276
Acquisition of leasehold acreage, geological and geophysical and other		75	(a)
Facilities and other capital in our core operating areas		100
Total	$	1,347

(a) Excludes approximately $113.6 million of acquisitions of oil and natural gas assets and their related asset retirement obligations we acquired in the first nine months of 2011. We do not plan or budget for these types of acquisitions.

Short-term interruptions in production. During February 2011, we experienced interruptions in production on most of our properties located in the Permian Basin due to sustained sub-freezing temperatures which caused operational problems with third party natural gas processing plants and the operational effectiveness of our well equipment. We estimate that these interruptions reduced our first quarter 2011 production by approximately 350 to 400 MBoe.

45

Derivative Financial Instruments

Derivative financial instrument exposure. At September 30, 2011, the fair value of our financial derivatives was a net asset of $234.5 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 derivative contracts are not financially viable. Our credit facility does not allow us to offset amounts we may owe a lender against amounts we may be owed related to our financial instruments with such party.

New commodity derivative contracts. During the nine months ended September 30, 2011, we entered into additional commodity derivative contracts to hedge a portion of our estimated future production. The following table summarizes information about these additional commodity derivative contracts for the nine months ended September 30, 2011. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Aggregate		Index		Contract
	Volume		Price (a)		Period
Oil (volumes in Bbls):
Price swap		115,000	$	96.65		03/01/11 - 11/30/11
Price swap		200,000	$	97.20		03/01/11 - 12/31/11
Price swap		190,000	$	111.41		05/01/11 - 07/31/11
Price swap		736,000	$	110.21		05/01/11 - 12/31/11
Price swap		66,000	$	111.80		08/01/11 - 11/30/11
Price swap		535,000	$	100.66		10/01/11 - 12/31/11
Price swap		45,000	$	99.35		01/01/12 - 03/31/12
Price swap		176,000	$	110.34		01/01/12 - 11/30/12
Price swap		2,244,000	$	103.83		01/01/12 - 12/31/12
Price swap		555,000	$	99.00		07/01/12 - 12/31/12
Price swap		210,000	$	103.65		01/01/13 - 06/30/13
Price swap		3,444,000	$	101.25		01/01/13 - 12/31/13

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

In October 2011, we entered into the following commodity derivative contracts to hedge additional amounts of our estimated future production:

	Aggregate Volume		Index Price (a)		Contract Period
Oil (volumes in Bbls):
Price swap		1,080,000	$	89.23		01/01/12 - 12/31/12
Price swap		27,000	$	89.10		07/01/12 - 09/30/12
Price swap		2,400,000	$	90.21		01/01/13 - 12/31/13

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

46

Results of Operations

The following table sets forth summary information concerning our production and operating data from our continuing operations for the three and nine months ended September 30, 2011 and 2010. The data in this table excludes results from the Marbob and Settlement Acquisitions for periods prior to their respective closing dates in October 2010. Also, the table below excludes production and operating data that we have classified as discontinued operations, which is more fully described in Note N of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).”

		00000000		00000000		00000000		00000000
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
Production and operating data:
Net production volumes:
Oil (MBbl)		3,869		2,460		10,501		6,613
Natural gas (MMcf)		14,652		7,098		38,929		19,081
Total (MBoe)		6,311		3,643		16,989		9,793
Average daily production volumes:
Oil (Bbl)		42,054		26,739		38,465		24,223
Natural gas (Mcf)		159,258		77,152		142,596		69,894
Total (Boe)		68,597		39,598		62,231		35,872
Average prices:
Oil, without derivatives (Bbl)	$	85.98	$	72.20	$	91.21	$	74.05
Oil, with derivatives (Bbl) (a)	$	83.90	$	72.62	$	82.77	$	72.24
Natural gas, without derivatives (Mcf)	$	8.31	$	6.79	$	7.80	$	7.05
Natural gas, with derivatives (Mcf) (a)	$	8.74	$	7.39	$	8.25	$	7.60
Total, without derivatives (Boe)	$	72.01	$	61.98	$	74.26	$	63.75
Total, with derivatives (Boe) (a)	$	71.73	$	63.43	$	70.06	$	63.59
Operating costs and expenses per Boe:
Lease operating expenses and workover costs	$	7.42	$	5.57	$	6.72	$	5.88
Oil and natural gas taxes	$	5.90	$	5.89	$	6.07	$	5.51
Depreciation, depletion and amortization	$	18.34	$	15.82	$	17.95	$	16.07
General and administrative	$	3.62	$	4.20	$	3.94	$	4.78

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

		0000000000		0000000000		0000000000		0000000000
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Gain (loss) on derivatives not designated as hedges:
Cash receipts from (payments on) oil derivatives	$	(8,051)	$	1,034	$	(88,679)	$	(11,951)
Cash receipts from natural gas derivatives		6,263		4,258		17,468		10,378
Cash payments on interest rate derivatives		-		(1,224)		(6,624)		(3,658)
Unrealized mark-to-market gain (loss) on commodity and interest rate derivatives		387,010		(70,175)		374,797		67,460
Gain (loss) on derivatives not designated as hedges	$	385,222	$	(66,107)	$	296,962	$	62,229

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.

47

The following table sets forth summary production and operating data from our discontinued operations for the three and nine months ended September 30, 2011 and 2010. The discontinued operations presentation is the result of reclassifying the results of operations from the divestitures of our non-core Permian Basin assets in December 2010 and our Bakken assets in March 2011, which are more fully described in Note N of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).”

		000000		000000			000000		000000
	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2011		2010			2011		2010
Production and operating data:
Net production volumes:
Oil (MBbl)		-		196			117		550
Natural gas (MMcf)		-		362			37		1,312
Total (MBoe)		-		256			123		769
Average daily production volumes:
Oil (Bbl)		-		2,130			429		2,015
Natural gas (Mcf)		-		3,935			136		4,806
Total (Boe)		-		2,786			451		2,816
Average prices:
Oil, without derivatives (Bbl)	$	-	$	68.24		$	80.82	$	69.91
Oil, with derivatives (Bbl) (a)	$	-	$	68.24		$	80.82	$	69.91
Natural gas, without derivatives (Mcf)	$	-	$	3.67		$	1.84	$	4.18
Natural gas, with derivatives (Mcf) (a)	$	-	$	3.67		$	1.84	$	4.18
Total, without derivatives (Boe)	$	-	$	57.44		$	77.43	$	57.12
Total, with derivatives (Boe) (a)	$	-	$	57.44		$	77.43	$	57.12
Operating costs and expenses per Boe:
Lease operating expenses and workover costs	$	-	$	7.51		$	3.85	$	8.56
Oil and natural gas taxes	$	-	$	5.42		$	9.50	$	5.34
Depreciation, depletion and amortization	$	-	$	16.70		$	17.13	$	16.19
General and administrative	$	-	$	(0.94	) (b)	$	-	$	(0.89	) (b)

  (a) None of our derivatives not designated as hedges related to discontinued operations.

  (b) Represents the fees received from third-parties for operating oil and natural gas properties that were sold. We reflect these fees as a reduction of general and administrative expenses.

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Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

Oil and natural gas revenues. Revenue from oil and natural gas operations was $454.5 million for the three months ended September 30, 2011, an increase of $228.7 million (101 percent) from $225.8 million for the three months ended September 30, 2010. This increase was primarily due to (i) increases in realized oil and natural gas prices, (ii) increased production as a result of the Marbob and Settlement Acquisitions and (iii) successful drilling efforts during 2010 and 2011. Specific factors affecting oil and natural gas revenues include the following:

• the average realized oil price (excluding the effects of derivative activities) was $85.98 per Bbl during the three months ended September 30, 2011, an increase of 19 percent from $72.20 per Bbl during the three months ended September 30, 2010;

• total oil production was 3,869 MBbl for the three months ended September 30, 2011, an increase of 1,409 MBbl (57 percent) from 2,460 MBbl for the three months ended September 30, 2010;

• the average realized natural gas price (excluding the effects of derivative activities) was $8.31 per Mcf during the three months ended September 30, 2011, an increase of 22 percent from $6.79 per Mcf during the three months ended September 30, 2010. 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;

• total natural gas production was 14,652 MMcf for the three months ended September 30, 2011, an increase of 7,554 MMcf (106 percent) from 7,098 MMcf for the three months ended September 30, 2010; and

• total production for the three months ended September 30, 2011 includes 232 MBoe (2,522 Boe per day) primarily relating to an underestimate of production in the first and second quarters of 2011.

Production expenses. The following table provides the components of our total oil and natural gas production costs for the three months ended September 30, 2011 and 2010:

		000000000		000000000		000000000		000000000
	Three Months Ended September 30,
	2011				2010
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Lease operating expenses	$	46,587	$	7.39	$	20,388	$	5.60
Taxes:
Ad valorem		2,671		0.42		1,990		0.54
Production		34,593		5.48		19,482		5.35
Workover costs		199		0.03		(98)		(0.03)
Total oil and natural gas production expenses	$	84,050	$	13.32	$	41,762	$	11.46

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

Lease operating expenses for the three months ended September 30, 2011 includes a $9.5 million ($1.50 per Boe) underestimate of costs primarily related to the first and second quarters of 2011.

Lease operating expenses were $46.6 million ($7.39 per Boe) for the three months ended September 30, 2011, an increase of $26.2 million (128 percent) from $20.4 million ($5.60 per Boe) for the three months ended September 30, 2010. The increase in lease operating expenses was primarily due to (i) our wells successfully drilled and completed in 2010 and 2011, (ii) the Marbob and Settlement Acquisitions which closed in October 2010, (iii) cost pressures in labor, environmental and salt water disposal costs and (iv) an underestimate of costs in periods prior to third quarter 2011 mentioned above. The increase in lease operating expenses per Boe was in part due to cost pressures in labor, environmental and salt water disposal costs and the underestimate of costs in periods prior to

49

third quarter 2011 mentioned above, offset in part by additional production from our wells successfully drilled and completed in 2010 and 2011 where we are receiving benefits from economies of scale.

Ad valorem taxes have increased primarily as a result of increased valuations of our Texas properties and a greater number of producing wells primarily associated with 2010 and 2011 drilling activity in Texas.

Production taxes per unit of production were $5.48 per Boe during the three months ended September 30, 2011, an increase of 2 percent from $5.35 per Boe during the three months ended September 30, 2010. The slight increase was related to increased commodity prices, significantly offset by a $2.2 million ($0.56 per Boe) overstatement of production taxes for the three months ended September 30, 2010 due to a prior period adjustment on one of our assets in our New Mexico Shelf area. Over the same period, our per Boe commodity prices (excluding the effects of derivatives) increased 16.2 percent.

Workover expenses were approximately $0.2 million for the three months ended September 30, 2011. The 2011 workover expenses were incurred primarily in the Texas Permian area and were incurred to increase production. Workover amounts for the three months ended September 30, 2010 were a result of an overestimate of costs in periods prior to third quarter 2010.

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the three months ended September 30, 2011 and 2010:

		000000000000		000000000000
	Three Months Ended September 30,
(in thousands)	2011		2010
Geological and geophysical	$	2,859	$	441
Leasehold abandonments and other		639		3,176
Total exploration and abandonments	$	3,498	$	3,617

Our geological and geophysical expense, which primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, was $2.9 million and $0.4 million, primarily related to the Texas Permian area, for the three months ended September 30, 2011 and 2010, respectively.

Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the three months ended September 30, 2011 and 2010:

		0000000000		0000000000		0000000000		0000000000
	Three Months Ended September 30,
	2011				2010
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties	$	113,865	$	18.04	$	56,470	$	15.50
Depreciation of other property and equipment		1,477		0.23		766		0.21
Amortization of intangible asset  -  operating rights		388		0.07		388		0.11
Total depletion, depreciation and amortization	$	115,730	$	18.34	$	57,624	$	15.82
Oil price used to estimate proved oil reserves at period end	$	91.00			$	73.85
Natural gas price used to estimate proved natural gas reserves at period end	$	4.16			$	4.41

Depletion of proved oil and natural gas properties was $113.9 million ($18.04 per Boe) for the three months ended September 30, 2011, an increase of $57.4 million (102 percent) from $56.5 million ($15.50 per Boe) for the three months ended September 30, 2010. The increase in depletion expense was primarily due to (i) capitalized costs associated with new wells that were successfully drilled and completed in 2010 and 2011 and (ii) the Marbob and Settlement Acquisitions, offset in part by the increase in oil and natural gas prices between the periods utilized to determine proved reserves.

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

Impairment of long-lived assets. We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. A $1.9 million charge was recorded for the three months ended September 30, 2010 due to weaker oil prices and declines in well performance during the three months ended September 30, 2010.

General and administrative expenses. The following table provides components of our general and administrative expenses for the three months ended September 30, 2011 and 2010:

		000000000		000000000		000000000		000000000
	Three Months Ended September 30,
	2011				2010
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
General and administrative expenses  -  recurring	$	21,779	$	3.45	$	15,227	$	4.18
Non-recurring bonus paid to Henry Entities’ employees		-		-		121		0.03
Non-cash stock-based compensation		4,673		0.74		3,152		0.87
Less: Third-party operating fee reimbursements		(3,579)		(0.57)		(3,215)		(0.88)
Total general and administrative expenses	$	22,873	$	3.62	$	15,285	$	4.20

General and administrative expenses were $22.9 million ($3.62 per Boe) for the three months ended September 30, 2011, an increase of $7.6 million (50 percent) from $15.3 million ($4.20 per Boe) for the three months ended September 30, 2010. The increase in general and administrative expenses on an aggregate basis was primarily due to an increase in (i) non-cash stock-based compensation expense for stock-based compensation awards and (ii) the number of employees and related personnel expenses to handle our increased activities, partially offset by an absence of a non-recurring bonus due to the former Henry Entities’ employees during the three months ended September 30, 2011. The decrease in total general and administrative expenses per Boe was primarily due to increased production associated with (i) additional production from our wells successfully drilled and completed in 2010 and 2011 and (ii) additional production from our Marbob and Settlement Acquisitions for which we added an incremental number of administrative personnel.

In connection with the Henry Entities acquisition in July 2008, we agreed to pay certain of the Henry Entities’ former employees a predetermined bonus amount, in addition to the compensation we pay these employees, at each of the first and second anniversaries of the closing of the acquisition. Since these employees earned this bonus over the two years following the acquisition and it is outside of our control, we are reflecting the cost in our general and administrative costs as non-recurring. The final payment of the Henry Entities bonuses occurred in July 2010.

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. As we drill more wells in which we own a higher working interest, these reimbursements, on a per Boe basis, could decrease over time. We earned reimbursements of $3.6 million and $3.2 million during the three months ended September 30, 2011 and 2010, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations.

51

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 September 30, 2011 and 2010:

	Three Months Ended
	September 30,
(in thousands)	2011		2010
Cash payments (receipts):
Commodity derivatives  -  oil	$	8,051	$	(1,034)
Commodity derivatives  -  natural gas		(6,263)		(4,258)
Financial derivatives  -  interest		-		1,224
Mark-to-market (gain) loss:
Commodity derivatives  -  oil		(390,327)		79,815
Commodity derivatives  -  natural gas		3,317		(10,300)
Financial derivatives  -  interest		-		660
(Gain) loss on derivatives not designated as hedges	$	(385,222)	$	66,107

Interest expense. The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the three months ended September 30, 2011 and 2010:

	Three Months Ended
	September 30,
(dollars in thousands)	2011		2010
Interest expense	$	32,881	$	12,036
Weighted average cash interest rate		6.3%		5.5%
Weighted average debt balance	$	1,806,201	$	698,038

The increase in weighted average debt balance during the three months ended September 30, 2011 was due primarily to borrowings in October 2010 to fund the cash consideration for the Marbob and Settlement Acquisitions. The increase in interest expense is due to (i) an increase in the weighted average debt balance between periods, (ii) an increase in amortization of capitalized loan costs, primarily associated with the financing costs of the Marbob Acquisition and the 2011 amendments to our credit facility, (iii) the December 2010 issuance of senior notes due 2021 and (iv) the May 2011 issuance of senior notes due 2022. The increase in the weighted average cash interest rate is primarily due to the issuance of our senior notes, which bear a higher fixed interest rate than was available under our credit facility.

Income tax provisions. We recorded an income tax expense from continuing operations of $221.2 million and $7.4 million for the three months ended September 30, 2011 and 2010, respectively. The effective income tax rate for the three months ended September 30, 2011 and 2010 was 38.3 percent and 31.4 percent, respectively.

52

Income from discontinued operations, net of tax. We made the following divestitures:

	Asset Group
	Permian Basin	Bakken
(dollars in millions)	Assets	Assets
Date divested	December 2010	March 2011
Net proceeds	$              103.3	$            195.9
Gain on sale of assets	$                29.1	$            142.0

As a result, we have reflected the results of operations of these divested assets as discontinued operations, rather than as a component of continuing operations. See Note N 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. We recognized income from discontinued operations of $4.6 million for the three months ended September 30, 2010. There was no activity related to the divested assets during the three months ended September 30, 2011.

53

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Oil and natural gas revenues. Revenue from oil and natural gas operations was $1,261.5 million for the nine months ended September 30, 2011, an increase of $637.2 million (102 percent) from $624.3 million for the nine months ended September 30, 2010. This increase was primarily due to (i) increases in realized oil and natural gas prices, (ii) increased production as a result of the Marbob and Settlement Acquisitions and (iii) successful drilling efforts during 2010 and 2011, partially offset by the previously discussed production interruptions due to weather in February 2011. Specific factors affecting oil and natural gas revenues include the following:

• the average realized oil price (excluding the effects of derivative activities) was $91.21 per Bbl during the nine months ended September 30, 2011, an increase of 23 percent from $74.05 per Bbl during the nine months ended September 30, 2010;

• total oil production was 10,501 MBbl for the nine months ended September 30, 2011, an increase of 3,888 MBbl (59 percent) from 6,613 MBbl for the nine months ended September 30, 2010;

• the average realized natural gas price (excluding the effects of derivative activities) was $7.80 per Mcf during the nine months ended September 30, 2011, an increase of 11 percent from $7.05 per Mcf during the nine months ended September 30, 2010. 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; and

• total natural gas production was 38,929 MMcf for the nine months ended September 30, 2011, an increase of 19,848 MMcf (104 percent) from 19,081 MMcf for the nine months ended September 30, 2010.

Production expenses. The following table provides the components of our total oil and natural gas production costs for the nine months ended September 30, 2011 and 2010:

	Nine Months Ended September 30,
	2011				2010
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Lease operating expenses	$	113,049	$	6.66	$	54,446	$	5.56
Taxes:
Ad valorem		8,013		0.47		6,517		0.66
Production		95,156		5.60		47,483		4.85
Workover costs		1,067		0.06		3,088		0.32
Total oil and natural gas production expenses	$	217,285	$	12.79	$	111,534	$	11.39

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

Lease operating expenses for the nine months ended September 30, 2011 includes a $4.0 million ($0.24 per Boe) underestimate of costs in periods prior to 2011.

Lease operating expenses were $113.0 million ($6.66 per Boe) for the nine months ended September 30, 2011, an increase of $58.6 million (108 percent) from $54.4 million ($5.56 per Boe) for the nine months ended September 30, 2010. The increase in lease operating expenses was primarily due to (i) our wells successfully drilled and completed in 2010 and 2011, (ii) the Marbob and Settlement Acquisitions which closed in October 2010 and (iii) an underestimate of costs in periods prior to 2011 mentioned above. The increase in lease operating expenses per Boe was primarily due to (i) cost increases in services and supplies primarily related to an increase in commodity prices, (ii) cost pressures in labor, environmental and salt water disposal costs, (iii) cost pressures in labor, environmental and salt water disposal costs and (iv) an underestimate of costs in periods prior to 2011 mentioned above, offset in part

54

by additional production from our wells successfully drilled and completed in 2010 and 2011 where we are receiving benefits from economies of scale.

Ad valorem taxes have increased primarily as a result of increased valuations of our Texas properties and the increase in our number of wells successfully drilled in 2010 and 2011 in Texas.

Production taxes per unit of production were $5.60 per Boe during the nine months ended September 30, 2011, an increase of 15 percent from $4.85 per Boe during the nine months ended September 30, 2010. The increase was directly related to our increased revenues. Over the same period, our per Boe commodity prices (excluding the effects of derivatives) increased 16 percent.

Workover expenses were approximately $1.1 million and $3.1 million for the nine months ended September 30, 2011 and 2010, respectively. The 2011 amounts related primarily to workovers in the Texas Permian area, while the 2010 amounts related primarily to activity in both the Texas Permian and New Mexico Shelf areas performed to increase production.

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the nine months ended September 30, 2011 and 2010:

	Nine Months Ended September 30,
(in thousands)	2011		2010
Geological and geophysical	$	3,817	$	1,653
Exploratory dry holes		12		92
Leasehold abandonments and other		795		3,903
Total exploration and abandonments	$	4,624	$	5,648

Our geological and geophysical expense, which primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, was $3.8 million and $1.7 million, primarily related to the Texas Permian area, for the nine months ended September 30, 2011 and 2010, respectively.

Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the nine months ended September 30, 2011 and 2010:

	Nine Months Ended September 30,
	2011				2010
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties	$	300,106	$	17.66	$	154,064	$	15.73
Depreciation of other property and equipment		3,631		0.21		2,168		0.22
Amortization of intangible asset - operating rights		1,162		0.08		1,162		0.12
Total depletion, depreciation and amortization	$	304,899	$	17.95	$	157,394	$	16.07
Oil price used to estimate proved oil reserves at period end	$	91.00			$	73.85
Natural gas price used to estimate proved natural gas reserves at period end	$	4.16			$	4.41

Depletion of proved oil and natural gas properties was $300.1 million ($17.66 per Boe) for the nine months ended September 30, 2011, an increase of $146.0 million (95 percent) from $154.1 million ($15.73 per Boe) for the nine months ended September 30, 2011. The increase in depletion expense was primarily due to capitalized costs associated with new wells that were successfully drilled and completed in 2010 and 2011 and the Marbob and Settlement Acquisitions, and was offset in part by the increase in the oil and natural gas prices between the periods utilized to determine proved reserves.

55

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

Impairment of long-lived assets. We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Due primarily to downward adjustments to the economically recoverable proved reserves associated with declines in well performance, we recognized a non-cash charge against earnings of approximately $0.1 million and $5.7 million during the nine months ended September 30, 2011 and 2010, respectively, which was primarily attributable to natural gas related properties in our New Mexico Shelf area.

General and administrative expenses. The following table provides components of our general and administrative expenses for the nine months ended September 30, 2011 and 2010:

	Nine Months Ended September 30,
	2011				2010
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
General and administrative expenses - recurring	$	62,311	$	3.67	$	42,223	$	4.31
Non-recurring bonus paid to Henry Entities’ employees		-		-		5,059		0.52
Non-cash stock-based compensation		13,866		0.82		8,854		0.90
Less: Third-party operating fee reimbursements		(9,294)		(0.55)		(9,312)		(0.95)
Total general and administrative expenses	$	66,883		3.94	$	46,824	$	4.78

General and administrative expenses were $66.9 million ($3.94 per Boe) for the nine months ended September 30, 2011, an increase of $20.1 million (43 percent) from $46.8 million ($4.78 per Boe) for the nine months ended September 30, 2010. The increase in aggregate general and administrative expenses was primarily due to an increase in (i) non-cash stock-based compensation expense for stock-based compensation awards and (ii) the number of employees and related personnel expenses to handle our increased activities, partially offset by the absence of a non-recurring bonus due to the former Henry Entities’ employees during the nine months ended September 30, 2011. The decrease in total general and administrative expenses per Boe was primarily due to increased production associated with (i) additional production from our wells successfully drilled and completed in 2010 and 2011 and (ii) additional production from our Marbob and Settlement Acquisitions for which we added an incremental number of administrative personnel.

In connection with the Henry Entities acquisition in July 2008, we agreed to pay certain of the Henry Entities’ former employees a predetermined bonus amount, in addition to the compensation we pay these employees, at each of the first and second anniversaries of the closing of the acquisition. Since these employees earned this bonus over the two years following the acquisition and it is outside of our control, we are reflecting the cost in our general and administrative costs as non-recurring. The final payment of the Henry Entities bonuses occurred in July 2010.

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. As we drill more wells in which we own a higher working interest, these reimbursements, on a per Boe basis, could decrease over time. We earned reimbursements of $9.3 million for both the nine months ended September 30, 2011 and 2010. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations.

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(Gain) loss on derivatives not designated as hedges. The following table sets forth the cash settlements and the non-cash mark-to-market adjustments for the derivative contracts not designated as hedges for the nine months ended September 30, 2011 and 2010:

		00000000		00000000
	Nine Months Ended September 30,
(in thousands)	2011		2010
Cash payments (receipts):
Commodity derivatives - oil	$	88,679	$	11,951
Commodity derivatives - natural gas		(17,468)		(10,378)
Financial derivatives - interest		6,624		3,658
Mark-to-market (gain) loss:
Commodity derivatives - oil		(381,385)		(40,926)
Commodity derivatives - natural gas		12,342		(30,978)
Financial derivatives - interest		(5,754)		4,444
Gain on derivatives not designated as hedges	$	(296,962)	$	(62,229)

Interest expense. The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the nine months ended September 30, 2011 and 2010:

	Nine Months Ended September 30,
(dollars in thousands)	2011		2010
Interest expense	$	84,201	$	34,293
Weighted average cash interest rate		6.0%		5.4%
Weighted average debt balance	$	1,750,944	$	690,797

The increase in weighted average debt balance during the nine months ended September 30, 2011 was due primarily to borrowings in October 2010 to fund the cash consideration for the Marbob and Settlement Acquisitions. The increase in interest expense is due to (i) an increase in the weighted average debt balance between periods, (ii) an increase in amortization of capitalized loan costs, primarily associated with the financing costs of the Marbob Acquisition and the 2011 amendments to our credit facility, (iii) the December 2010 issuance of senior notes due 2021 and (iv) the May 2011 issuance of senior notes due 2022; partially offset by an $8.5 million benefit from the write-off of the remaining original issue premium on the 8% unsecured senior note due to Marbob paid in full in May 2011. The increase in the weighted average cash interest rate is primarily due to the issuance of our senior notes, which bear a higher fixed interest rate than was available under our credit facility.

Income tax provisions. We recorded an income tax expense from continuing operations of $334.0 million and $118.4 million for the nine months ended September 30, 2011 and 2010, respectively. The effective income tax rate for the nine months ended September 30, 2011 and 2010 was 38.2 percent and 37.0 percent, respectively.

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Income from discontinued operations, net of tax. We made the following divestitures:

	Asset Group
	Permian Basin	Bakken
(dollars in millions)	Assets	Assets
Date divested	December 2010	March 2011
Net proceeds	$              103.3	$            195.9
Gain on sale of assets	$                29.1	$            142.0

As a result, we have reflected the results of operations of these divested assets as discontinued operations, rather than as a component of continuing operations. See Note N 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. We recognized income from discontinued operations of $91.2 million and $11.2 million for the nine months ended September 30, 2011 and 2010, respectively. In 2011, income from discontinued operations included a pre-tax gain on the sale of these assets of approximately $142.0 million.

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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 and/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 nine months ended September 30, 2011 and 2010 totaled $974.7 million and $471.5 million, respectively, as compared to the comparable amount in cash flows used by investing activities of $932.8 million and $486.9 million for the respective periods. The primary reason for the differences in the costs incurred and cash flow expenditures is the timing of payments. The 2011 expenditures were funded in part from borrowings under our credit facility.

For 2011, we expected capital expenditures to total approximately $1.35 billion, excluding the costs of acquisitions other than customary leasehold purchases of acreage. Based on current commodity prices and capital costs, we believe our 2011 planned capital expenditures, excluding the effects of acquisitions, will exceed our 2011 cash flow, and we expect to fund any such shortfall with borrowings under our credit facility.

In November 2011, we announced our 2012 capital budget of approximately $1.3 billion, which we expect can be funded within our cash flow, based on current commodity prices and capital costs. Cost inflation has been experienced industry-wide and particularly in the Permian Basin due to the increased activity levels. As our size and financial flexibility have grown, we now take a longer-term view on spending within our cash flow, and our spending during any specific period may exceed our cash flow for that period. However, our capital budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in our costs, we may reduce our capital spending program to be substantially within our cash flow.

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

Other than the customary purchase of leasehold acreage, our 2011 and 2012 capital budgets are exclusive of acquisitions. We do not have a specific acquisition budget, since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek to acquire oil and natural gas properties that provide opportunities for the addition of reserves and production through a combination of development, high-potential exploration and control of operations that will allow us to apply our operating expertise.

Acquisitions. Our expenditures for acquisitions of proved and unproved properties during the three months ended September 30, 2011 and 2010 totaled approximately $42.4 million and $14.6 million, respectively, and approximately $186.9 million and $49.4 million during the nine months ended September 30, 2011 and 2010, respectively. The acquisitions of proved properties during the nine months ended September 30, 2011 primarily relate to additional Wolfberry assets. Expenditures for leasehold acreage acquisitions (which are expenditures we generally provide for in the budget) included in the total above were approximately $73.3 million for the nine months ended September 30, 2011.

Divestitures. In March 2011, we sold our Bakken assets for cash consideration of approximately $195.9 million and recognized a gain on the disposition of assets (included in discontinued operations) of approximately $142.0 million. For the first quarter 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.

In December 2010, we sold certain of our non-core Permian Basin assets for cash consideration of approximately $103.3 million and recognized a gain of approximately $29.1 million. For all of 2010, these assets produced an average of approximately 1,393 Boe per day, of which approximately 46 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 our officers, derivative liabilities and other obligations. Since

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December 31, 2010, the material changes in our contractual obligations included a $121.0 million increase in outstanding long-term borrowings, a $280.6 million increase in cash interest expense on debt and a $147.5 million decrease in our net commodity derivative liability. See Note J 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 nine months ended September 30, 2011.

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

Capital resources. Our primary sources of liquidity have been cash flows generated from operating activities (including the cash settlements received from (paid on) derivatives not designated as hedges presented in our investing activities) and financing provided by our credit facility. We currently believe that our cash flows alone will not meet both our short-term working capital requirements and our current 2011 capital expenditure plans. We believe, however, 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 decrease in cash and cash equivalents for the nine months ended September 30, 2011 and 2010:

	Nine Months Ended September 30,
(in thousands)	2011		2010
Net cash provided by operating activities	$	778,986	$	402,756
Net cash used in investing activities		(957,745)		(512,824)
Net cash provided by financing activities		178,549		107,191
Net decrease in cash and cash equivalents	$	(210)	$	(2,877)

Cash flow from operating activities. Our net cash provided by operating activities was $779.0 million and $402.8 million for the nine months ended September 30, 2011 and 2010, respectively. The increase in operating cash flows during the nine months ended September 30, 2011 over the same period in 2010 was principally due to increases in average realized oil prices coupled with increased production, offset by cost increases in services and supplies primarily related to the increase in oil prices. Our net cash provided by operating activities also includes reductions of $110.4 million and $55.1 million for the nine months ended September 30, 2011 and 2010, 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 from investing activities. During the nine months ended September 30, 2011 and 2010, our cash flows used in investing activities were $957.7 million and $512.8 million, respectively, for additions to, and acquisitions of, oil and natural gas properties (inclusive of dry hole costs) and settlements paid on derivatives not designated as hedges, offset by proceeds from the sale of assets. Cash flows used in investing activities were higher during the nine months ended September 30, 2011 over 2010, due to an increase in (i) our capital expenditures on oil and natural gas properties and (ii) our settlements on derivatives, offset by the proceeds from the sale of our divested assets in the first quarter of 2011.

Cash flow from financing activities. Net cash provided by financing activities was $178.5 million and $107.2 million for the nine months ended September 30, 2011 and 2010, respectively. During the nine months ended September 30, 2011 and 2010, we completed the following significant capital markets activities:

• In May 2011, we issued $600 million in principal amount of 6.5% unsecured senior notes due 2022 at par, and we received net proceeds of approximately $587.1 million. We used the net proceeds from this offering to repay a portion of the borrowings under our credit facility to increase our liquidity for future activities; and

• In February 2010, we issued 5,347,500 shares of our common stock at $42.75 per share. After deducting underwriting discounts of approximately $9.1 million and transaction costs, we received net proceeds of approximately $219.3 million. The net proceeds from this offering were used to repay a portion of the borrowings under our credit facility.

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During the nine months ended September 30, 2011, we reduced our outstanding balance on our credit facility by $321 million primarily using the $195.9 million of proceeds from the sale of our Bakken assets and the net proceeds of our May 2011 debt offering of approximately $587.1 million, offset in part by the amount that our capital expenditures exceeded our operating cash flow in 2011. During the nine months ended September 30, 2010, we made net payments of $157.5 million on our credit facility, primarily funded by our issuance of 5.3 million shares of our common stock for approximately $219.3 million in the first quarter of 2010.

In 2011, we amended our credit facility to increase the borrowing base from $2.0 billion to $2.5 billion and maintained our commitments from our bank group at $2.0 billion. The next scheduled borrowing base redetermination will be in April 2012. Between scheduled borrowing base redeterminations, we and, if requested by 66 2/3 percent of the lenders, the lenders, may each request one special redetermination. Our credit facility has a maturity date of April 25, 2016. At September 30, 2011, we had no letters of credit outstanding under the credit facility, and our availability to borrow additional funds was approximately $1.7 billion based on the bank commitments of $2.0 billion.

Advances on the Credit Facility bear interest, at our option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) (3.25 percent at September 30, 2011) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). The Credit Facility’s interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest margins ranging from 150 to 250 basis points and 50 to 150 basis points, respectively, per annum depending on the debt balance outstanding. We pay commitment fees on the unused portion of the available commitment ranging from 37.5 to 50 basis points per annum, depending on utilization of the commitments.

In conducting our business, we may utilize various financing sources, including the issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock, (iv) common stock and/or (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. The use 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 September 30, 2011, we had $0.2 million of cash on hand, and our availability to borrow additional funds under our credit facility was approximately $1.7 billion.

At September 30, 2011, the commitments under our credit facility were $2.0 billion which provided us with approximately $1.7 billion of available borrowing capacity. In 2011, we amended our credit facility, which primarily (i) increased our borrowing base $500 million to $2.5 billion (leaving our $2.0 billion in commitments from our bank group in place) until the next borrowing base redetermination in April 2012, (ii) extended maturity approximately three years to April 2016, (iii) improved our pricing grid and (iv) allowed us to issue up to an additional $1.0 billion in senior notes.

Upon a redetermination, our 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 “B1” 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 September 30, 2011 was $4.8 billion, consisting of debt of $1.8 billion and stockholders’ equity of $3.0 billion. Our debt to book capitalization was 36.9 percent and 41.2 percent at September 30, 2011 and December 31, 2010, respectively. Our ratio of current assets to current liabilities was 0.83 to 1.0 at September 30, 2011 as compared to 0.65 to 1.0 at December 31, 2010.

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 nine months ended September 30, 2011, we received an average of $91.21 per barrel of oil and $7.80 per Mcf of natural gas before consideration of commodity derivative contracts compared to $74.05 per barrel of oil and $7.05 per Mcf of natural gas in the nine

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months ended September 30, 2010. 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, commodity prices for oil and natural gas increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends have put pressure not only on our operating costs, but also on capital costs.

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 has been no material changes in our critical accounting policies and procedures during the nine months ended September 30, 2011. See our disclosure of critical accounting policies in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K and in our Current Report on Form 8-K, which amended and replaced certain portions of our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the United States Securities and Exchange Commission (the “SEC”) on May 18, 2011.

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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 “Item 7A. Quantitative and Qualitative Disclosure About Market Risk” of our Annual Report on Form 10-K and in our Current Report on Form 8-K, which amended and replaced certain portions of our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on May 18, 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 September 30, 2011, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit. We do not enter into derivative or other financial instruments for speculative or trading purposes.

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

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

We 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 common stock. An average increase in the commodity price of $10.00 per barrel of oil and $1.00 per MMBtu for natural gas from the commodity prices at September 30, 2011, would have decreased the net fair value asset on our commodity price risk management contracts by approximately $201.9 million.

At September 30, 2011, we had (i) oil price swaps that settle on a monthly basis covering future oil production from October 1, 2011 through June 30, 2015 and (ii) a natural gas price swap and natural gas basis swaps covering future natural gas production from October 1, 2011 to December 31, 2012. See Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on our commodity derivative contracts. The average NYMEX oil price and average NYMEX natural gas prices for the nine months ended September 30, 2011 was $95.46 per Bbl and $4.21 per MMBtu, respectively. At November 1, 2011, the NYMEX oil price and NYMEX natural gas price were $92.19 per Bbl and $3.78 per MMBtu, respectively. A decrease in oil and natural gas prices would increase the net fair value asset of our commodity derivative contracts from their recorded balance at September 30, 2011. Changes in the recorded fair value of the undesignated commodity derivative contracts are marked to market through earnings as unrealized gains or losses. The potential increase in our net fair value asset would be recorded in earnings as an unrealized gain. However, an increase in the average NYMEX oil and natural gas price above those at September 30, 2011, would result in a decrease in our net fair value asset and be recorded as an unrealized loss in earnings. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.

Interest rate risk. Our exposure to changes in interest rates relates primarily to debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. In the past we have entered into interest rate risk management arrangements for a portion of our outstanding debt in order to reduce our exposure to changes in interest rates. We may enter into additional interest rate risk management arrangements in the future. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall

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leverage of the debt portfolio. We are exposed to changes in interest rates as a result of our credit facility, and the terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available borrowing base.

We had total indebtedness of $0.3 billion outstanding under our credit facility at September 30, 2011. The impact of a 1 percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $3.0 million.

The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method during 2011. During 2011, we were party to commodity and interest rate derivative instruments. See Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the nine months ended September 30, 2011:

	Derivative Instruments Net Assets (Liabilities)  (a)
(in thousands)	Commodities		Interest Rate (b)		Total
Fair value of contracts outstanding at December 31, 2010	$	(134,580)	$	(5,754)	$	(140,334)
Changes in fair values (c)		297,832		(870)		296,962
Contract maturities and terminations		71,211		6,624		77,835
Fair value of contracts outstanding at September 30, 2011	$	234,463	$	-	$	234,463

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

(b) We terminated our interest rate swaps in May 2011.

(c) New derivative contracts entered into by us have no intrinsic value at inception.

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 September 30, 2011 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) and Rule 15d-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the other information set forth in this 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, 2010, 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. Except for the risk factor set forth below, 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, 2010 and in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011. The risks described in this Quarterly Report on Form 10-Q, in our Annual Report on Form 10-K and in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 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.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. In addition, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities, including well stimulation and completion activities such as hydraulic fracturing, are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

• environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

• abnormally pressured or structured formations;

• mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

• fires, explosions and ruptures of pipelines;

• personal injuries and death; and

• natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

• injury or loss of life;

• damage to and destruction of property and equipment;

• damage to natural resources due to underground migration of hydraulic fracturing fluids;

• pollution and other environmental damage, including spillage or mishandling of recovered hydraulic fracturing fluids;

• regulatory investigations and penalties;

• suspension of our operations; and

• repair and remediation costs.

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We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse effect on our production, revenues and results of operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of our drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the U.S. Environmental Protection Agency (“EPA”) recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision.

At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of the Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the U.S. Securities and Exchange Commission to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. Legislation also has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanism.

In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Colorado, Pennsylvania, and Wyoming have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. In addition, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding chemical ingredients and additives used in the hydraulic fracturing process. The Railroad Commission of Texas has issued proposed regulations to implement these disclosure requirements. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

Further, on July 28, 2011, the EPA issued proposed rules that would subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured natural gas wells. These standards include the reduced emission completion (“REC”) techniques developed in the EPA’s Natural Gas STAR program along with pit flaring of natural gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (“MACT”) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. We are currently researching the effect these proposed rules could have on our business. Final action on the proposed rules is expected no later than February 28, 2012.

If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

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

					Total number		Maximum
Period	Total number of shares withheld (1)		Average price per share		of shares purchased as part of publicly announced plans		number of shares that may yet be purchased under the plan
July 1, 2011 - July 31, 2011		529	$	92.02		-
August 1, 2011 - August 31, 2011		2,121	$	83.65		-
September 1, 2011 - September 30, 2011		-	$	-		-

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

Item 5. Other Information

We are filing a revised report from Cawley, Gillespie & Associates, Inc. (“Cawley”), our independent petroleum engineers, included in Exhibit 23.2 to this Quarterly Report on Form 10-Q, which is a letter dated January 24, 2011 regarding proved reserves. This revised report makes certain clarifications with respect to its effective date and the prices used. Other than these changes, there have been no other change to the Cawley report filed as Exhibit 23.2 to this Quarterly Report on Form 10-Q.

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

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Item 6. Exhibits

Exhibit Number	Exhibit
3.1	Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).
3.2	Amended and Restated Bylaws of Concho Resources Inc., as amended March 25, 2008 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on March 26, 2008, and incorporated herein by reference).
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Current Report on Form S-1/A on July 5, 2007, and incorporated herein by reference).
10.1	Seventh Amendment to Amended and Restated Credit Agreement, dated as of October 12, 2011, among Concho Resources Inc. and the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on October 14, 2011, and incorporated herein by reference).
23.1 (a)	Consent of Cawley, Gillespie & Associates, Inc.
23.2 (a)	Cawley, Gillespie & Associates, Inc. Reserve Report.
31.1 (a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 (a)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 (b)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 (b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS (a)	XBRL Instance Document.
101.SCH (a)	XBRL Schema Document.
101.CAL (a)	XBRL Calculation Linkbase Document.
101.DEF (a)	XBRL Definition Linkbase Document.
101.LAB (a)	XBRL Labels Linkbase Document.
101.PRE (a)	XBRL Presentation Linkbase Document.

(a)   Filed herewith.

(b)   Furnished herewith.

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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:	November 3, 2011	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
3.1	Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).
3.2	Amended and Restated Bylaws of Concho Resources Inc., as amended March 25, 2008 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on March 26, 2008, and incorporated herein by reference).
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Current Report on Form S-1/A on July 5, 2007, and incorporated herein by reference).
10.1	Seventh Amendment to Amended and Restated Credit Agreement, dated as of October 12, 2011, among Concho Resources Inc. and the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on October 14, 2011, and incorporated herein by reference).
23.1 (a)	Consent of Cawley, Gillespie & Associates, Inc.
23.2 (a)	Cawley, Gillespie & Associates, Inc. Reserve Report.
31.1 (a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 (a)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 (b)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 (b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS (a)	XBRL Instance Document.
101.SCH (a)	XBRL Schema Document.
101.CAL (a)	XBRL Calculation Linkbase Document.
101.DEF (a)	XBRL Definition Linkbase Document.
101.LAB (a)	XBRL Labels Linkbase Document.
101.PRE (a)	XBRL Presentation Linkbase Document.

(a)   Filed herewith.

(b)   Furnished herewith.