Concho Resources 10Q 2010 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2010


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

For the transition period from to

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)


Delaware		76-0818600

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

550 West Texas Avenue, Suite 100
Midland, Texas		79701

(Address of principal executive offices)		(Zip code)

(432) 683-7443

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

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). Yesþ Noo

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. (Check one):


Large accelerated filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
	(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

Number of shares of the registrant’s common stock outstanding at November 2, 2010: 99,883,995 shares

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, 2009, 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;

•

risks related to the integration of the assets of Marbob Energy Corporation and affiliates (“Marbob”) and its former employees, along with other recently acquired assets, with our operations;

•

drilling and operating risks;

•

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

•

the effects of government regulation, permitting and other legal requirements, 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 risk management program;

•

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

•

risks and liabilities associated with acquired properties or businesses, including the Marbob assets;

•

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

•

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

•

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

•

competition in the oil and natural gas industry;

•

uncertainty concerning our assumed or possible future results of operations; and

•

our existing indebtedness, as well as the increase in our indebtedness as a result of the Marbob acquisition.

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

PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)


Consolidated Balance Sheets at September 30, 2010 and December 31, 2009			1
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009			2
Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2010			3
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009			4
Condensed Notes to Consolidated Financial Statements			5

iii

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited


	September 30,			December 31,
(in thousands, except share and per share data)	2010			2009

Assets
Current assets:
Cash and cash equivalents	$	357		$	3,234
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas		99,402			69,199
Joint operations and other		101,421			100,120
Related parties		311			216
Derivative instruments		23,339			1,309
Deferred income taxes		2,551			29,284
Prepaid costs and other		11,295			13,896

Total current assets		238,676			217,258

Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		3,871,715			3,358,004
Accumulated depletion and depreciation		(692,922	)		(517,421	)

Total oil and natural gas properties, net		3,178,793			2,840,583
Other property and equipment, net		17,105			15,706

Total property and equipment, net		3,195,898			2,856,289

Deferred loan costs, net		19,544			20,676
Intangible asset, net — operating rights		35,360			36,522
Inventory		20,903			16,255
Noncurrent derivative instruments		20,105			23,614
Other assets		11,189			471

Total assets	$	3,541,675		$	3,171,085

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	7,133		$	15,443
Related parties		474			291
Other current liabilities:
Bank overdrafts		38,551			3,415
Revenue payable		40,785			31,069
Accrued and prepaid drilling costs		174,000			164,282
Derivative instruments		27,104			62,419
Other current liabilities		62,098			60,095

Total current liabilities		350,145			337,014

Long-term debt		688,620			845,836
Deferred income taxes		677,573			603,286
Noncurrent derivative instruments		15,713			29,337
Asset retirement obligations and other long-term liabilities		21,002			20,184
Commitments and contingencies (Note K)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 91,908,877 and 85,815,926 shares issued at September 30, 2010 and December 31, 2009, respectively		92			86
Additional paid-in capital		1,270,887			1,029,392
Retained earnings		518,853			306,367
Treasury stock, at cost; 27,044 and 12,380 shares at September 30, 2010 and December 31, 2009, respectively		(1,210	)		(417	)

Total stockholders’ equity		1,788,622			1,335,428

Total liabilities and stockholders’ equity	$	3,541,675		$	3,171,085

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

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands, except per share amounts)	2010			2009			2010			2009

Operating revenues:
Oil sales	$	190,977		$	121,301		$	528,129		$	287,786
Natural gas sales		49,519			32,193			140,077			79,042

Total operating revenues		240,496			153,494			668,206			366,828

Operating costs and expenses:
Oil and natural gas production		45,072			25,439			122,220			76,022
Exploration and abandonments		3,625			2,776			5,798			10,195
Depreciation, depletion and amortization		61,900			54,835			169,844			157,985
Accretion of discount on asset retirement obligations		405			220			1,177			799
Impairments of long-lived assets		1,922			1,131			9,234			9,686
General and administrative (including non-cash stock-based compensation of $3,152 and $2,548 for the three months ended September 30, 2010 and 2009, respectively, and $8,854 and $6,661 for the nine months ended September 30, 2010 and 2009, respectively)		15,045			12,715			46,141			38,633
Bad debt expense		6			—			578			—
(Gain) loss on derivatives not designated as hedges		66,107			7,783			(62,229	)		94,435

Total operating costs and expenses		194,082			104,899			292,763			387,755

Income (loss) from operations		46,414			48,595			375,443			(20,927	)

Other income (expense):
Interest expense		(12,036	)		(6,809	)		(34,293	)		(17,379	)
Other, net		(3,521	)		(200	)		(3,898	)		(348	)

Total other expense		(15,557	)		(7,009	)		(38,191	)		(17,727	)

Income (loss) before income taxes		30,857			41,586			337,252			(38,654	)
Income tax benefit (expense)		(10,082	)		(21,824	)		(124,766	)		11,973

Net income (loss)	$	20,775		$	19,762		$	212,486		$	(26,681	)

Basic earnings per share:
Net income (loss) per share	$	0.23		$	0.23		$	2.35		$	(0.31	)

Weighted average shares used in basic earnings per share		91,182			85,061			90,361			84,798

Diluted earnings per share:
Net income (loss) per share	$	0.22		$	0.23		$	2.32		$	(0.31	)

Weighted average shares used in diluted earnings per share		92,440			86,088			91,631			84,798

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

Concho Resources Inc.

Consolidated Statement of Stockholders’ Equity

Unaudited


						Additional									Total
	Common Stock					Paid-in		Retained		Treasury Stock					Stockholders’
(in thousands)	Shares			Amount		Capital		Earnings		Shares		Amount			Equity

BALANCE AT DECEMBER 31, 2009		85,816		$	86	$	1,029,392	$	306,367		12	$	(417	)	$	1,335,428
Net income		—			—		—		212,486		—		—			212,486
Issuance of common stock		5,348			5		219,303		—		—		—			219,308
Stock options exercised		465			1		4,370		—		—		—			4,371
Grants of restricted stock		288			—		—		—		—		—			—
Cancellation of restricted stock		(8	)		—		—		—		—		—			—
Stock-based compensation		—			—		8,854		—		—		—			8,854
Excess tax benefits related to stock-based compensation		—			—		8,968		—		—		—			8,968
Purchase of treasury stock		—			—		—		—		15		(793	)		(793	)

BALANCE AT SEPTEMBER 30, 2010		91,909		$	92	$	1,270,887	$	518,853		27	$	(1,210	)	$	1,788,622

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

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited


	Nine Months Ended
	September 30,
(in thousands)	2010			2009

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	212,486		$	(26,681	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		169,844			157,985
Impairments of long-lived assets		9,234			9,686
Accretion of discount on asset retirement obligations		1,177			799
Exploration and abandonments, including dry holes		4,121			6,950
Non-cash compensation expense		8,854			6,661
Bad debt expense		578			—
Deferred income taxes		109,988			(21,840	)
Loss on sale of assets		24			147
(Gain) loss on derivatives not designated as hedges		(62,229	)		94,435
Other non-cash items		3,760			2,656
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		(35,505	)		(10,367	)
Prepaid costs and other		(700	)		(2,519	)
Inventory		(4,673	)		(3,979	)
Accounts payable		(8,127	)		5,029
Revenue payable		9,716			17,581
Other current liabilities		(15,792	)		(4,465	)

Net cash provided by operating activities		402,756			232,078

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and natural gas properties		(486,903	)		(316,756	)
Acquisition of oil and natural gas properties		(17,730	)		—
Additions to other property and equipment		(3,750	)		(3,716	)
Proceeds from the sale of oil and natural gas properties and other assets		790			1,004
Settlements received from (paid on) derivatives not designated as hedges		(5,231	)		77,590

Net cash used in investing activities		(512,824	)		(241,878	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		840,500			672,650
Payments of long-term debt		(998,000	)		(656,916	)
Net proceeds from issuance of common stock		219,308			—
Exercise of stock options		4,371			4,501
Excess tax benefit related to stock-based compensation		8,968			3,357
Payments for loan origination costs		(2,299	)		(8,933	)
Purchase of treasury stock		(793	)		(292	)
Bank overdrafts		35,136			(6,624	)

Net cash provided by financing activities		107,191			7,743

Net decrease in cash and cash equivalents		(2,877	)		(2,057	)
Cash and cash equivalents at beginning of period		3,234			17,752

Cash and cash equivalents at end of period	$	357		$	15,695

SUPPLEMENTAL CASH FLOWS:
Cash paid for interest and fees, net of $119 and $33 capitalized interest	$	27,627		$	13,291
Cash paid for income taxes	$	17,771		$	5,598
NON-CASH INVESTING ACTIVITIES:
Deferred tax effect of acquired oil and natural gas properties	$	—		$	(835	)

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

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2010

Unaudited

Note A.Organization and nature of operations

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

Note B.Summary of significant accounting policies

Principles of consolidation.The consolidated financial statements of the Company include the accounts of the Company and its wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated.

Use of estimates in the preparation of financial statements.Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties 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, purchase price allocations for business combinations and fair value of stock-based compensation.

Interim financial statements.The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2009 is derived from audited consolidated financial statements. In the opinion of management, the accompanying consolidated financial statements reflect all adjustments necessary to present fairly the Company’s financial position at September 30, 2010, its results of operations for the three and nine months ended September 30, 2010 and 2009 and its cash flows for the nine months ended September 30, 2010 and 2009. All such adjustments are of a normal recurring nature. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed or omitted from these consolidated financial statements. Accordingly, these consolidated financial statements should be read with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

Deferred loan costs.Deferred loan costs are stated at cost, net of amortization, which is computed using the effective interest and straight-line methods.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Future amortization expense of deferred loan costs at September 30, 2010 was as follows:


(in thousands)

Remaining 2010	$	1,232
2011		4,973
2012		5,057
2013		3,433
2014		1,132
Thereafter		3,717

Total	$	19,544

Intangible assets.The Company capitalized certain operating rights acquired in 2008. The gross operating rights, which have no residual value, are amortized over the estimated economic life of approximately 25 years. Impairment will be assessed if indicators of potential impairment exist or when there is a material change in the remaining useful economic life. The following table reflects the gross and net intangible assets at September 30, 2010 and December 31, 2009:


	September 30,			December 31,
(in thousands)	2010			2009

Gross intangible — operating rights	$	38,717		$	38,717
Accumulated amortization		(3,357	)		(2,195	)

Net intangible — operating rights	$	35,360		$	36,522

The following table reflects amortization expense for the three and nine months ended September 30, 2010 and 2009:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2010		2009		2010		2009

Amortization expense	$	388	$	387	$	1,162	$	1,168

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

The following table reflects the estimated aggregate amortization expense for each of the periods presented below at September 30, 2010:


(in thousands)

Remaining 2010	$	386
2011		1,549
2012		1,549
2013		1,549
2014		1,549
Thereafter		28,778

Total	$	35,360

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, 2010 and December 31, 2009 as well as amounts reflected in oil and natural gas production expense for the three and nine months ended September 30, 2010 and 2009:


							September 30,			December 31,
(dollars in thousands)							2010			2009

Natural gas imbalance receivable (included in other assets)							$	432		$	444
Undertake position (Mcf)								96,002			98,584

Natural gas imbalance liability (included in asset retirement obligations and other long-term liabilities)							$	512		$	533
Overtake position (Mcf)								96,483			101,278

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(dollars in thousands)	2010			2009			2010			2009

Value of net undertake arising during the period decreasing oil and natural gas production expense	$	(14	)	$	(9	)	$	(9	)	$	(49	)
Net undertake position arising during the period (Mcf)		(3,221	)		(1,882	)		(2,213	)		(11,951	)

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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

General and administrative expense.The Company receives fees for the operation of jointly owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $3.5 million and $3.2 million for the three months ended September 30, 2010 and 2009, respectively, and $10.0 million and $8.6 million for the nine months ended September 30, 2010 and 2009, respectively.

Recent accounting pronouncements.

Various topics.In February 2010, the Financial Accounting Standards Board (the “FASB”) issued an update to various topics, which eliminated outdated provisions and inconsistencies in the Accounting Standards Codification (the “Codification”), and clarified certain guidance to reflect the FASB’s original intent. The update is effective for the first reporting period, including interim periods, beginning after issuance of the update, except for the amendments affecting embedded derivatives and reorganizations. In addition to amending the Codification, the FASB made corresponding changes to the legacy accounting literature to facilitate historical research. These changes are included in an appendix to the update. The Company adopted the update effective January 1, 2010, and the adoption did not have a significant impact on the Company’s consolidated financial statements.

Accounting for extractive activities.In April 2010, the FASB issued an amendment to a paragraph in the accounting standard for oil and natural gas extractive activities accounting. The standard adds to the Codification the SEC’sModernization of Oil and Gas Reportingrelease. The Company adopted the update effective April 20, 2010, and the adoption did not have a significant impact on the Company’s consolidated financial statements.

Note C.Exploratory well costs

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are 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, 2010:


	Three Months Ended			Nine Months Ended
(in thousands)	September 30, 2010			September 30, 2010

Beginning capitalized exploratory well costs	$	32,862		$	8,668
Additions to exploratory well costs pending the determination of proved reserves		60,649			125,145
Reclassifications due to determination of proved reserves		(62,488	)		(102,790	)
Exploratory well costs charged to expense		—			—

Ending capitalized exploratory well costs	$	31,023		$	31,023

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

The following table provides an aging, at September 30, 2010 and December 31, 2009, of capitalized exploratory well costs based on the date drilling was completed:


	September 30,		December 31,
(in thousands)	2010		2009

Wells in drilling progress	$	9,731	$	1,767
Capitalized exploratory well costs that have been capitalized for a period of one year or less		21,292		6,901
Capitalized exploratory well costs that have been capitalized for a period greater than one year		—		—

Total capitalized exploratory well costs	$	31,023	$	8,668

At September 30, 2010, the Company had 41 gross exploratory wells waiting on their completion, including 28 wells in the Texas Permian area, 11 wells in the New Mexico Permian area and two wells in the emerging plays area.

Note D.Business combinations

Wolfberry acquisitions.In December 2009, together with the acquisition of related additional interests that closed in 2010, the Company closed two acquisitions (the “Wolfberry Acquisitions”) of interests in producing and non-producing assets in the Wolfberry play in the Permian Basin for approximately $270.7 million. The Wolfberry Acquisitions were primarily funded with borrowings under the Company’s credit facility. The Company’s 2009 results of operations do not include any production, revenues or costs from the Wolfberry Acquisitions.

The following table represents the allocation of the total purchase price of the Wolfberry Acquisitions to the acquired assets and liabilities. The allocation represents the fair values assigned to each of the assets acquired and liabilities assumed:


(in thousands)

Fair value of the Wolfberry Acquisitions’ net assets:	��
Proved oil and natural gas properties	$	212,987
Unproved oil and natural gas properties		58,222

Total assets acquired		271,209

Asset retirement obligations assumed		(464	)

Net purchase price	$	270,745

Note E.Asset retirement obligations

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

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

The following table summarizes the Company’s asset retirement obligation transactions recorded during the three and nine months ended September 30, 2010 and 2009:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2010			2009			2010			2009

Asset retirement obligations, beginning of period	$	22,057		$	14,386		$	22,754		$	16,809
Liabilities incurred from new wells		1,144			132			2,255			402
Accretion expense		405			220			1,177			799
Disposition of wells		—			(81	)		—			(223	)
Liabilities settled upon plugging and abandoning wells		(522	)		(630	)		(819	)		(983	)
Revision of estimates		(626	)		107			(2,909	)		(2,670	)

Asset retirement obligations, end of period	$	22,458		$	14,134		$	22,458		$	14,134

Note F.Stockholders’ equity

Equity issuance.On February 1, 2010, the Company issued 5,347,500 shares of its common stock at $42.75 per share. After deducting underwriting discounts of approximately $9.1 million and transaction costs, the Company received net proceeds of approximately $219.3 million. The net proceeds from this offering were used to repay a portion of the borrowings under the Company’s credit facility.

Private placement of equity.On July 19, 2010, the Company entered into a Common Stock Purchase Agreement (the “Purchase Agreement”) with certain third-party accredited investors (the “Purchasers”) to sell 6,622,517 shares of its common stock at a price of $45.30 per share in a private placement (the “Private Placement”) for aggregate cash consideration of approximately $300 million. Also, the Company entered into a registration rights agreement with the investors. The Company paid approximately $7.3 million in transaction costs, which includes the placement agent fee. The common stock was issued and sold simultaneously with the closing of the acquisition of substantially all of the oil and natural gas properties and related assets owned by Marbob Energy Corporation and certain affiliated entities (collectively, “Marbob”) (the “Marbob Acquisition”) on October 7, 2010 (See Note Q). The Company used the net proceeds to finance a portion of the Marbob Acquisition.

Treasury stock.The restrictions on certain restricted stock awards issued to certain of the Company’s officers, directors and key employees lapsed, and upon the lapse of restrictions these individuals became liable for income taxes on the value of such shares. In accordance with the Company’s 2006 Stock Incentive Plan and the applicable restricted stock award agreements, some of such persons elected to deliver shares of the Company’s common stock to the Company in exchange for cash used to satisfy such tax liability. In total, at September 30, 2010 and December 31, 2009, the Company had acquired 27,044 and 12,380 shares, respectively, that were held as treasury stock in the approximate amounts of $1.2 million and $0.4 million, respectively.

Note G.Incentive plans

Defined contribution plan.The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees and maintained certain other acquired plans. Currently, the Company matches 100 percent of employee contributions, not to exceed 6 percent of the employee’s annual salary. The Company contributions to the plans for the three months ended September 30, 2010 and 2009, were approximately $0.3 million and $0.3 million, respectively, and approximately $0.4 million and $0.8 million for the nine months ended September 30, 2010 and 2009, respectively.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Stock incentive plan.The Company’s 2006 Stock Incentive Plan (together with applicable stock option agreements and restricted stock agreements, the “Plan”) provides for granting stock options and restricted stock awards to employees and individuals associated with the Company. The following table shows the number of existing awards and awards available under the Plan at September 30, 2010:


	Number of
	Common Shares

Approved and authorized awards		5,850,000
Stock option grants, net of forfeitures		(3,463,720	)
Restricted stock grants, net of forfeitures		(1,085,140	)

Awards available for future grant		1,301,140

Restricted stock awards.All restricted shares are treated as issued and outstanding in the accompanying consolidated balance sheets. Holders of restricted stock are eligible to vote and receive dividends, if any. If an employee terminates employment prior the restriction lapse date, the awarded shares that have not vested as of the date of termination of employment are forfeited and cancelled and are no longer considered issued and outstanding. A summary of the Company’s restricted stock awards activity under the Plan for the nine months ended September 30, 2010 is presented below:


	Number of			Grant Date
	Restricted			Fair Value
	Shares			Per Share

*Restricted stock:*

Outstanding at December 31, 2009		497,257
Shares granted		288,315		$	50.20
Shares cancelled / forteited		(8,229	)
Lapse of restrictions		(168,295	)

Outstanding at September 30, 2010		609,048

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
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, 2010 and 2009:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2010		2009		2010			2009

*Grant date fair value for awards during the period and change in fair value due to modification:*
Employee grants	$	1,916	$	382	$	9,257	^(a)	$	5,002
Officer and director grants		215		84		5,290			1,934

Total	$	2,131	$	466	$	14,547		$	6,936


*Stock-based compensation expense from restricted stock:*
Employee grants	$	1,450	$	792	$	3,568		$	2,185
Officer and director grants		1,138		441		3,134			1,248

Total	$	2,588	$	1,233	$	6,702		$	3,433


*Income taxes and other information:*
Income tax benefit related to restricted stock	$	972	$	137	$	2,525		$	1,064
Deductions in current taxable income related to restricted stock	$	6,227	$	699	$	9,186		$	5,066


(a)		Includes effects of modifications to certain stock-based awards for the nine months ended September 30, 2009.

Stock option awards.A summary of the Company’s stock option awards activity under the Plan for the nine months ended September 30, 2010 is presented below:


				Weighted
				Average
	Number of			Exercise
	Options			Price

*Stock options:*

Outstanding at December 31, 2009		2,156,503		$	14.11
Options granted		—		$	—
Options exercised		(465,365	)	$	9.39

Outstanding at September 30, 2010		1,691,138		$	15.41


Vested at end of period		1,287,609		$	13.56


Exercisable at end of period		875,525		$	16.09

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

The following table summarizes information about the Company’s vested and exercisable stock options outstanding at September 30, 2010:


				Weighted
				Average	Weighted
		Number		Remaining	Average
		of Stock		Contractual	Exercise		Intrinsic
		Options		Life	Price		Value

							(in thousands)
*Vested options:*

September 30, 2010:
Exercise price	$8.00		584,332	1.74 years	$	8.00	$	33,991
Exercise price	$12.00		92,450	4.24 years	$	12.00		5,008
Exercise price	$12.50 - $15.50		311,250	6.12 years	$	14.49		16,086
Exercise price	$20.00 - $23.00		234,453	7.55 years	$	21.67		10,433
Exercise price	$28.00 - $37.27		65,124	7.76 years	$	32.00		2,225

			1,287,609	4.34 years	$	13.56	$	67,743


*Exercisable options:*

September 30, 2010:
Exercise price	$8.00		190,076	2.76 years	$	8.00	$	11,057
Exercise price	$12.00		74,622	4.95 years	$	12.00		4,042
Exercise price	$12.50 - $15.50		311,250	6.12 years	$	14.49		16,086
Exercise price	$20.00 - $23.00		234,453	7.55 years	$	21.67		10,433
Exercise price	$28.00 - $37.27		65,124	7.76 years	$	32.00		2,225

			875,525	5.80 years	$	16.09	$	43,843

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

The following table summarizes information about stock-based compensation for stock options for the three and nine months ended September 30, 2010 and 2009:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2010		2009		2010		2009

*Grant date fair value for awards during the period and change in fair value due to modification:*

Employee grants	$	—	$	50	$	—	$	50
Officer and director grants^(a)		—		2,907		—		4,361

Total	$	—	$	2,957	$	—	$	4,411


*Stock-based compensation expense from stock options:*

Employee grants	$	39	$	132	$	125	$	273
Officer and director grants		525		1,183		2,027		2,955

Total	$	564	$	1,315	$	2,152	$	3,228


*Income taxes and other information:*
Income tax benefit related to stock options	$	213	$	194	$	812	$	1,000
Deductions in current taxable income related to stock options exercised	$	1,548	$	1,729	$	19,672	$	8,886


(a)		The three and nine months ended September 30, 2009 include effects of modifications to certain stock-based awards.

The Company used the simplified method that is accepted by the United States Securities and Exchange Commission (“SEC”) to calculate the expected term for stock options granted during the nine months ended September 30, 2009, since it did not have sufficient historical exercise data to provide a reasonable basis upon which to estimate expected term due to the limited period of time its shares of common stock have been publicly traded. Expected volatilities are based on a combination of historical and implied volatilities of comparable companies.

Future stock-based compensation expense.Future stock-based compensation expense based on the awards outstanding at September 30, 2010 is summarized in the table below:


	Restricted		Stock
(in thousands)	Stock		Options		Total

Remaining 2010	$	2,599	$	501	$	3,100
2011		6,914		879		7,793
2012		4,039		184		4,223
2013		1,594		15		1,609
2014		90		—		90

Total	$	15,236	$	1,579	$	16,815

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Note H.Disclosures about fair value of financial instruments

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


*Level 1*:		Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.


*Level 2*:		Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company utilizes its counterparties’ valuations to assess the reasonableness of its prices and valuation techniques.


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

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis at September 30, 2010, for each of the fair value hierarchy levels:


	Fair Value Measurements at Reporting Date Using
			Significant
	Quoted Prices in		Other			Significant
	Active Markets for		Observable			Unobservable		Fair Value at
	Identical Assets		Inputs			Inputs		September 30,
(in thousands)	(Level 1)		(Level 2)			(Level 3)		2010

Assets:
Commodity derivative price swap contracts	$	—	$	90,616		$	—	$	90,616
Commodity derivative price collar contracts		—		—			5,651		5,651

		—		90,616			5,651		96,267

Liabilities:
Commodity derivative price swap contracts		—		(83,879	)		—		(83,879	)
Commodity derivative basis swap contracts		—		(4,816	)		—		(4,816	)
Interest rate derivative swap contracts		—		(6,945	)		—		(6,945	)

		—		(95,640	)		—		(95,640	)

Net financial assets (liabilities)	$	—	$	(5,024	)	$	5,651	$	627

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


(in thousands)

Balance at December 31, 2009	$	(945	)
Realized and unrealized gains, net		9,730
Settlements (receipts), net		(3,134	)

Balance at September 30, 2010	$	5,651


Total gains for the period included in earnings attributable to the change in unrealized gains relating to assets (liabilities) still held at the reporting date	$	6,596

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table presents the carrying amounts and fair values of the Company’s financial instruments at September 30, 2010 and December 31, 2009:


	September 30, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
(in thousands)	Value		Value		Value		Value

Assets:
Derivative instruments	$	43,444	$	43,444	$	24,923	$	24,923

Liabilities:
Derivative instruments	$	42,817	$	42,817	$	91,756	$	91,756
Credit facility	$	392,500	$	396,491	$	550,000	$	528,849
8.625% senior notes due 2017	$	296,120	$	318,000	$	295,836	$	315,000

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

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

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

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Derivative instruments.The fair value of the Company’s derivative instruments are estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables (i) summarize the valuation of each of the Company’s financial instruments by required pricing levels and (ii) summarize 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, 2010 and December 31, 2009:


	Fair Value Measurements Using
			Significant					Total
	Quoted Prices in		Other			Significant		Fair Value
	Active Markets for		Observable			Unobservable		at
	Identical Assets		Inputs			Inputs		September 30,
(in thousands)	(Level 1)		(Level 2)			(Level 3)		2010

Assets⁽¹⁾
Current:^(a)
Commodity derivative price swap contracts	$	—	$	47,557		$	—	$	47,557
Commodity derivative price collar contracts		—		—			5,651		5,651

		—		47,557			5,651		53,208

Noncurrent:^(b)
Commodity derivative price swap contracts		—		43,059			—		43,059
Interest rate derivative swap contracts		—		—			—		—

		—		43,059			—		43,059

Liabilities⁽¹⁾
Current:^(a)
Commodity derivative price swap contracts		—		(48,233	)		—		(48,233	)
Commodity derivative basis swap contracts		—		(4,044	)		—		(4,044	)
Interest rate derivative swap contracts		—		(4,696	)		—		(4,696	)

		—		(56,973	)		—		(56,973	)

Noncurrent:^(b)
Commodity derivative price swap contracts		—		(35,646	)		—		(35,646	)
Commodity derivative basis swap contracts		—		(772	)		—		(772	)
Interest rate derivative swap contracts		—		(2,249	)		—		(2,249	)

		—		(38,667	)		—		(38,667	)

Net financial assets	$	—	$	(5,024	)	$	5,651	$	627


(a) Total current financial assets, gross basis								$	(3,765	)

(b) Total noncurrent financial assets, gross basis									4,392

Net financial assets								$	627

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited


	Fair Value Measurements Using
			Significant						Total
	Quoted Prices in		Other			Significant			Fair Value
	Active Markets for		Observable			Unobservable			at
	Identical Assets		Inputs			Inputs			December 31,
(in thousands)	(Level 1)		(Level 2)			(Level 3)			2009

Assets⁽¹⁾
Current:^(a)
Commodity derivative price swap contracts	$	—	$	13,850		$	—		$	13,850
Commodity derivative price collar contracts		—		—			134			134

		—		13,850			134			13,984

Noncurrent:^(b)
Commodity derivative price swap contracts		—		35,016			—			35,016
Interest rate derivative swap contracts		—		1,369			—			1,369

		—		36,385			—			36,385

Liabilities⁽¹⁾
Current:^(a)
Commodity derivative price swap contracts		—		(65,351	)		—			(65,351	)
Commodity derivative basis swap contracts		—		(5,254	)		—			(5,254	)
Interest rate derivative swap contracts		—		(3,870	)		—			(3,870	)
Commodity derivative price collar contracts		—		—			(619	)		(619	)

		—		(74,475	)		(619	)		(75,094	)

Noncurrent:^(b)
Commodity derivative price swap contracts		—		(38,259	)		—			(38,259	)
Commodity derivative basis swap contracts		—		(3,389	)		—			(3,389	)
Commodity derivative price collar contracts		—		—			(460	)		(460	)

		—		(41,648	)		(460	)		(42,108	)

Net financial liabilities	$	—	$	(65,888	)	$	(945	)	$	(66,833	)


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

Net financial liabilities									$	(66,833	)


(1)		The fair value of derivative instruments reported in the Company’s consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table reports the net basis derivative fair values as reported in the consolidated balance sheets at September 30, 2010 and December 31, 2009:

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited


	September 30,			December 31,
(in thousands)	2010			2009

Consolidated Balance Sheet Classification:

Current derivative contracts:
Assets	$	23,339		$	1,309
Liabilities		(27,104	)		(62,419	)

Net current	$	(3,765	)	$	(61,110	)


Noncurrent derivative contracts:
Assets	$	20,105		$	23,614
Liabilities		(15,713	)		(29,337	)

Net noncurrent	$	4,392		$	(5,723	)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

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

The Company periodically reviews its proved oil and natural gas properties that are sensitive to oil and natural gas prices for impairment. Due primarily to downward adjustments to the economically recoverable resource potential associated with declines in commodity prices and well performance, the Company recognized impairment expense related to its proved oil and natural gas properties. The following table reports the carrying amounts, estimated fair values and impairment expense of long-lived assets for the three and nine months ended September 30, 2010 and 2009:


	Carrying		Estimated		Impairment
(in thousands)	Amount		Fair Value		Expense

Three Months Ended September 30, 2010	$	4,083	$	2,161	$	1,922
Three Months Ended September 30, 2009	$	1,760	$	629	$	1,131
Nine Months Ended September 30, 2010	$	17,859	$	8,625	$	9,234
Nine Months Ended September 30, 2009	$	15,935	$	6,249	$	9,686

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Asset retirement obligations —The Company estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note E for a summary of changes in asset retirement obligations.

Measurement information for assets that are measured at fair value on a nonrecurring basis was as follows:


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

Three Months Ended September 30, 2010:
Impairment of long-lived assets	$	—	$	—	$	2,161	$	1,922
Asset retirement obligations incurred in current period		—		—		1,144

Three Months Ended September 30, 2009:
Impairment of long-lived assets	$	—	$	—	$	629	$	1,131
Asset retirement obligations incurred in current period		—		—		132

Nine Months Ended September 30, 2010:
Impairment of long-lived assets	$	—	$	—	$	8,625	$	9,234
Asset retirement obligations incurred in current period		—		—		2,255

Nine Months Ended September 30, 2009:
Impairment of long-lived assets	$	—	$	—	$	6,249	$	9,686
Asset retirement obligations incurred in current period		—		—		402

Note I. Derivative financial instruments

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

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

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

New commodity derivative contracts in the first nine months of 2010.During the nine months ended September 30, 2010, the Company entered into additional commodity derivative contracts to hedge a portion of its estimated future production. The following table summarizes information about these additional commodity derivative contracts:


	Aggregate		Index			Contract
	Volume		Price			Period

Oil (volumes in Bbls):
Price swap		670,000	$	83.72	^(a)		1/1/10 – 12/31/10
Price swap		195,000	$	76.85	^(a)		3/1/10 – 12/31/10
Price swap		1,463,000	$	88.63	^(a)		5/1/10 – 12/31/10
Price swap		3,714,000	$	85.15	^(a)		1/1/11 – 12/31/11
Price swap		3,573,000	$	88.56	^(a)		1/1/12 – 12/31/12
Price swap		261,000	$	82.50	^(a)		7/1/12 – 12/31/12
Price swap		1,380,000	$	82.58	^(a)		1/1/13 – 12/31/13
Price swap		1,248,000	$	83.94	^(a)		1/1/14 – 12/31/14
Price swap		600,000	$	84.50	^(a)		1/1/15 – 6/30/15

Natural gas (volumes in MMBtus):
Price swap		418,000	$	5.99	^(b)		2/1/10 – 12/31/10
Price swap		1,250,000	$	5.55	^(b)		3/1/10 – 12/31/10
Price swap		5,076,000	$	6.14	^(b)		1/1/11 – 12/31/11
Price swap		300,000	$	6.54	^(b)		1/1/12 – 12/31/12


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

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

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Commodity derivative contracts at September 30, 2010.The following table sets forth the Company’s outstanding commodity derivative contracts at September 30, 2010:


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total

Oil Swaps:^(a)
*2010:*
Volume (Bbl)								1,651,936		1,651,936
Price per Bbl							$	76.43	$	76.43
*2011:*
Volume (Bbl)		1,858,436		1,781,436		1,665,436		1,567,436		6,872,744
Price per Bbl	$	81.34	$	81.54	$	81.77	$	82.00	$	81.65
*2012:*
Volume (Bbl)		1,113,000		1,098,000		1,069,000		1,058,000		4,338,000
Price per Bbl	$	92.37	$	92.52	$	92.99	$	93.14	$	92.75
*2013:*
Volume (Bbl)		345,000		345,000		345,000		345,000		1,380,000
Price per Bbl	$	82.58	$	82.58	$	82.58	$	82.58	$	82.58
*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)
*2010:*
Volume (MMBtu)								2,258,000		2,258,000
Price per MMBtu							$	6.03	$	6.03
*2011:*
Volume (MMBtu)		1,569,000		3,069,000		3,069,000		3,069,000		10,776,000
Price per MMBtu	$	6.36	$	6.62	$	6.62	$	6.62	$	6.58
*2012:*
Volume (MMBtu)		75,000		75,000		75,000		75,000		300,000
Price per MMBtu	$	6.54	$	6.54	$	6.54	$	6.54	$	6.54

Natural Gas Collars:^(b)
*2010:*
Volume (MMBtu)								1,500,000		1,500,000
Price per MMBtu							$	6.00 - $6.80	$	6.00 - $6.80
*2011:*
Volume (MMBtu)		1,500,000		—		—		—		1,500,000
Price per MMBtu	$	6.00 - $6.80		—		—		—	$	6.00 - $6.80

Natural Gas Basis Swaps:^(c)
*2010:*
Volume (MMBtu)								2,100,000		2,100,000
Price per MMBtu							$	0.85	$	0.85
*2011:*
Volume (MMBtu)		1,800,000		1,800,000		1,800,000		1,800,000		7,200,000
Price per MMBtu	$	0.87	$	0.76	$	0.76	$	0.76	$	0.79


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

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

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

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Interest rate derivative contracts.The Company has interest rate swaps which fix the LIBOR interest rate on $300 million of the Company’s bank debt at 1.90 percent for three years beginning in May 2009. For this portion of the Company’s bank debt, the all-in interest rate will be calculated by adding the fixed rate of 1.90 percent to a margin that ranges from 2.00 percent to 3.00 percent, depending on the amount of bank debt outstanding.

The following table summarizes the gains and losses reported in earnings related to the commodity and interest rate derivative instruments for the three and nine months ended September 30, 2010 and 2009:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2010			2009			2010			2009

*Gain (loss) on derivatives not designated as hedges:*

Cash (payments on) receipts from derivatives not designated as hedges:
Commodity derivatives:
Oil	$	1,034		$	13,971		$	(11,951	)	$	70,383
Natural gas		4,258			3,395			10,378			9,227
Interest rate derivatives		(1,224	)		(1,241	)		(3,658	)		(2,020	)

Mark-to-market gain (loss):
Commodity derivatives:
Oil		(79,815	)		(12,821	)		40,926			(156,920	)
Natural gas		10,300			(8,442	)		30,978			(13,460	)
Interest rate derivatives		(660	)		(2,645	)		(4,444	)		(1,645	)

Total gain (loss) on derivatives not designated as hedges	$	(66,107	)	$	(7,783	)	$	62,229		$	(94,435	)

All of the Company’s derivative contracts at September 30, 2010 are expected to settle by June 30, 2015.

Note J.Debt

The Company’s debt consisted of the following at September 30, 2010 and December 31, 2009:


	September 30,			December 31,
(in thousands)	2010			2009

Credit facility	$	392,500		$	550,000
8.625% unsecured senior notes due 2017		300,000			300,000
Less: unamortized original issue discount		(3,880	)		(4,164	)
Less: current portion		—			—

Total long-term debt	$	688,620		$	845,836

Credit facility.The Company’s credit facility, as amended (the “Credit Facility”), has a maturity date of July 31, 2013. At September 30, 2010, the Company’s borrowing base was $1.2 billion, it had letters of credit outstanding under the Credit Facility of approximately $25,000, and its availability to borrow additional funds was approximately $807.5 million. On October 7, 2010, in connection with the closing of the Marbob Acquisition (See Note Q), the Company entered into an amendment to its Credit Facility to increase the borrowing base from $1.2 billion to $2.0 billion. The next scheduled borrowing base redetermination will be in April 2011. 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.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

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, 2010) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). At September 30, 2010, the interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest margins ranging from 200 to 300 basis points and 112.5 to 212.5 basis points, respectively, per annum depending on the debt balance outstanding. At September 30, 2010, the Company paid commitment fees on the unused portion of the available borrowing base of 50 basis points per annum.

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

The Company’s obligations under the Credit Facility are secured by a first lien on substantially all of the Company’s oil and natural gas properties. In addition, all of the Company’s subsidiaries are guarantors and all general partner, limited partner and membership interests in the Company’s subsidiaries owned by the Company have been pledged to secure borrowings under the Credit Facility. The Credit Facility contains various restrictive covenants and compliance requirements which include (a) maintenance of certain financial ratios, including (i) a quarterly ratio of total debt to consolidated earnings before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and other noncash income and expenses to be no greater than 4.0 to 1.0, and (ii) a ratio of current assets to current liabilities, excluding noncash assets and liabilities related to financial derivatives and asset retirement obligations and including the unfunded amounts under the Credit Facility, to be no less than 1.0 to 1.0; (b) limits on the incurrence of additional indebtedness and certain types of liens; (c) restrictions as to mergers, combinations and dispositions of assets; and (d) restrictions on the payment of cash dividends. At September 30, 2010, the Company was in compliance with its covenants under the Credit Facility.

8.625% unsecured senior notes.On September 18, 2009, the Company completed its public offering of $300 million aggregate principal amount of 8.625% senior notes due 2017 (the “Senior Notes”). The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries.

The Senior Notes will mature on October 1, 2017, and interest is payable on the Senior Notes each April 1 and October 1. The Company received net proceeds of $288.2 million (net of related estimated offering costs), which were used to repay a portion of the outstanding borrowings under the Credit Facility.

The Company may redeem some or all of the Senior Notes at any time on or after October 1, 2013 at the redemption prices specified in the indenture governing the Senior Notes. The Company may also redeem up to 35 percent of the Senior Notes using all or a portion of the net proceeds of certain public sales of equity interests completed before October 1, 2012 at a redemption price as specified in the indenture. If the Company sells certain assets or experiences specific kinds of change of control, each as described in the indenture, each holder of the Senior Notes will have the right to require the Company to repurchase the Senior Notes at a purchase price described in the indenture plus accrued and unpaid interest, if any, to the date of repurchase. At September 30, 2010, the Company was in compliance with its covenants in the indenture governing the Senior Notes.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Future interest expense from the original issue discount on the Senior Notes at September 30, 2010 was as follows:


(in thousands)

Remaining 2010	$	100
2011		421
2012		462
2013		507
2014		557
Thereafter		1,833

Total	$	3,880

Principal maturities of debt.Principal maturities of debt outstanding at September 30, 2010 are as follows:


(in thousands)

2010	$	—
2011		—
2012		—
2013		392,500
2014 and thereafter		300,000

Total	$	692,500

Interest expense.The following amounts have been incurred and charged to interest expense for the three and nine months ended September 30, 2010 and 2009:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2010			2009			2010			2009

Cash payments for interest	$	5,983		$	6,395		$	27,746		$	13,324
Amortization of original issue discount		97			13			284			13
Amortization of deferred loan costs		1,227			883			3,431			2,596
Write-off of deferred loan costs and original issue discount		—			57			—			57
Net changes in accruals		4,792			(524	)		2,951			1,422

Interest costs incurred		12,099			6,824			34,412			17,412
Less: capitalized interest		(63	)		(15	)		(119	)		(33	)

Total interest expense	$	12,036		$	6,809		$	34,293		$	17,379

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Note K.Commitments and contingencies

Severance agreements.The Company has entered into severance and change in control agreements with all of its senior officers. The current annual salaries for the Company’s senior officers covered under such agreements total approximately $2.1 million.

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

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

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, 2010:


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

Daywork drilling contracts with related parties^(a)	$	1,000	$	1,000	$	—	$	—	$	—
Other daywork drilling contracts		250		250		—		—		—

Total contractual drilling commitments	$	1,250	$	1,250	$	—	$	—	$	—


^(a)		Consists of daywork drilling contracts with Silver Oak Drilling, LLC, an affiliate of Chase Oil Corporation (“Chase Oil”), a stockholder of the Company.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Operating leases.The Company leases vehicles, equipment and office facilities under non-cancellable operating leases. Lease payments associated with these operating leases for the three months ended September 30, 2010 and 2009 were approximately $0.3 million and $0.7 million, respectively, and approximately $1.4 million and $1.9 million for the nine months ended September 30, 2010 and 2009, respectively. Future minimum lease commitments under non-cancellable operating leases at September 30, 2010 were as follows:


(in thousands)

Remaining 2010	$	847
2011		2,445
2012		2,199
2013		2,151
2014 and thereafter		5,903

Total	$	13,545

Note L.Income taxes

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

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

At September 30, 2010, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2004 through 2009 remain subject to examination by the major tax jurisdictions.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Income tax provision.The Company’s income tax provision (benefit) and amounts separately allocated were attributable to the following items for the three and nine months ended September 30, 2010 and 2009:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2010			2009			2010			2009

Tax expense (benefit) related to income (loss) from operations	$	10,082		$	21,824		$	124,766		$	(11,973	)

Changes in stockholders’ equity:
Excess tax benefits related to stock-based compensation		(2,265	)		(365	)		(8,968	)		(3,357	)

	$	7,817		$	21,459		$	115,798		$	(15,330	)

The Company’s income tax provision (benefit) attributable to income (loss) from operations consisted of the following for the three and nine months ended September 30, 2010 and 2009:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2010		2009		2010		2009

*Current:*
U.S. federal	$	18	$	2,766	$	12,524	$	8,060
U.S. state and local		529		1,099		2,254		1,807

		547		3,865		14,778		9,867


*Deferred:*
U.S. federal		8,715		15,941		98,307		(19,162	)
U.S. state and local		820		2,018		11,681		(2,678	)

		9,535		17,959		109,988		(21,840	)

	$	10,082	$	21,824	$	124,766	$	(11,973	)

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

The Company’s provision for income taxes differed from the U.S. federal statutory rate of 35 percent primarily due to state income taxes and non-deductible expenses. The reconciliation between the tax expense computed by multiplying pretax income by the U.S. federal statutory rate and the reported amounts of income tax expense (benefit) was as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2010			2009			2010			2009

Income (loss) at U.S. federal statutory rate	$	10,800		$	14,555		$	118,038		$	(13,529	)
State income taxes (net of federal tax effect)		824			1,762			9,005			(830	)
Statutory depletion		(54	)		—			(232	)		—
Nondeductible expense & other		(1,488	)		5,507			(2,045	)		2,386

Income tax expense (benefit)	$	10,082		$	21,824		$	124,766		$	(11,973	)


Effective tax rate		32.7	%		52.5	%		37.0	%		31.0	%

Note M.Related parties

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)	2010		2009		2010		2009

*Charges incurred with Chase Oil and affiliates*^(a)	$	11,395	$	5,670	$	26,902	$	18,939

*Working interests owned by employees:*^(b)
Revenues distributed to employees	$	49	$	130	$	220	$	192
Joint interest payments received from employees	$	293	$	95	$	868	$	979
Acquisition of oil and natural gas interests from an employee	$	363	$	—	$	363	$	—

*Overriding royalty interests paid to Chase Oil affiliates*^(c)	$	412	$	402	$	1,458	$	901

*Royalty interests paid to a director of the Company*^(d)	$	42	$	39	$	121	$	95

*Amounts paid under consulting agreement with Steven L. Beal*^(e)	$	64	$	63	$	194	$	63

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited


	September 30,		December 31,
(in thousands)	2010		2009
*Amounts included in accounts receivable — related parties:*
Chase Oil and affiliates^(a)	$	197	$	87
Working interests owned by employees^(b)	$	114	$	129

*Amounts included in accounts payable — related parties:*
Chase Oil and affiliates^(a)	$	—	$	9
Working interests owned by employees^(b)	$	9	$	15
Overriding royalty interests of Chase Oil affiliates^(c)	$	454	$	255
Royalty interests of a director of the Company^(d)	$	11	$	12


(a)		The Company incurred charges for services rendered in the ordinary course of business from 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 tables above summarize the charges incurred as well as outstanding payables and receivables.

(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.

(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 attributable to such interest and amounts due at period end.

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

Saltwater disposal services agreement.Among the assets the Company acquired from Chase Oil is an undivided interest in a saltwater gathering and disposal system, which is owned and maintained under a written agreement among the Company and Chase Oil and certain of its affiliates, and under which the Company as operator gathers and disposes of produced water. The system is owned jointly by the Company and Chase Oil and its affiliates in undivided ownership percentages, which are annually redetermined as of January 1 on the basis of each party’s percentage contribution of the total volume of produced water disposed of through the system during the prior calendar year. As of January 1, 2010, the Company owned 97.5 percent of the system and Chase Oil and its affiliates owned 2.5 percent.

Purchase of residence.During the second quarter of 2010, the Company purchased the Houston, Texas residence of an officer of the Company. To effectuate the purchase, the Company engaged a third-party relocation company, who executed the purchase for

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

$920,000 and will subsequently sell the officer’s residence. The third-party relocation company appraised the fair value of the residence at $920,000.

Note N.Net income (loss) per share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares treated as outstanding for the period.

The computation of diluted income (loss) per share reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive to income (loss) were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. These amounts include unexercised capital options, stock options and restricted stock (as issued under the Plan and described in Note G). Potentially dilutive effects are calculated using the treasury stock method.

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and nine months ended September 30, 2010 and 2009:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2010		2009		2010		2009

*Weighted average common shares outstanding:*

Basic		91,182		85,061		90,361		84,798
Dilutive common stock options		845		789		892		—
Dilutive restricted stock		413		238		378		—

Diluted		92,440		86,088		91,631		84,798

Because the Company reported a net loss for the nine months ended September 30, 2009, a total of 2,338,749 stock options and 477,795 restricted shares, outstanding at September 30, 2009, were not included in the diluted loss per share computations. The inclusion of these equity instruments would have been anti-dilutive; therefore, the weighted average common shares reported for basic and diluted net loss per share were the same.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Note O.Other current liabilities

The following table provides the components of the Company’s other current liabilities at September 30, 2010 and December 31, 2009:


	September 30,		December 31,
(in thousands)	2010		2009

*Other current liabilities:*
Accrued production costs	$	26,360	$	24,128
Payroll related matters		9,754		14,490
Accrued interest		12,999		10,055
Asset retirement obligations		2,182		3,262
Other		10,803		8,160

Other current liabilities	$	62,098	$	60,095

Note P.Subsidiary guarantors

All of the Company’s wholly-owned subsidiaries have fully and unconditionally guaranteed the Senior Notes of the Company (See Note J). In accordance with practices accepted by the SEC, the Company has prepared Condensed Consolidating Financial Statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following Condensed Consolidating Balance Sheets at September 30, 2010 and December 31, 2009, and Condensed Consolidating Statements of Operations for the three and nine months ended September 30, 2010 and 2009 and Condensed Consolidating Statements of Cash Flows for the nine months ended September 30, 2010 and 2009, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors are not restricted from making distributions to the Company.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Condensed Consolidating Balance Sheet
September 30, 2010


	Parent		Subsidiary		Consolidating
(in thousands)	Issuer		Guarantors		Entries			Total

ASSETS
Accounts receivable — related parties	$	3,917,586	$	775,450	$	(4,692,725	)	$	311
Other current assets		30,546		207,819		—			238,365
Total oil and natural gas properties, net		—		3,178,793		—			3,178,793
Total property and equipment, net		—		17,105		—			17,105
Investment in subsidiaries		1,187,490		—		(1,187,490	)		—
Total other long-term assets		39,650		67,451		—			107,101

Total assets	$	5,175,272	$	4,246,618	$	(5,880,215	)	$	3,541,675


LIABILITIES AND EQUITY
Accounts payable — related parties	$	1,968,955	$	2,724,244	$	(4,692,725	)	$	474
Other current liabilities		36,704		312,967		—			349,671
Other long-term liabilities		692,371		21,917		—			714,288
Long-term debt		688,620		—		—			688,620
Equity		1,788,622		1,187,490		(1,187,490	)		1,788,622

Total liabilities and equity	$	5,175,272	$	4,246,618	$	(5,880,215	)	$	3,541,675

Condensed Consolidating Balance Sheet
December 31, 2009


	Parent		Subsidiary		Consolidating
(in thousands)	Issuer		Guarantors		Entries			Total

ASSETS
Accounts receivable — related parties	$	2,715,307	$	1,738,382	$	(4,453,473	)	$	216
Other current assets		33,561		183,481		—			217,042
Total oil and natural gas properties, net		—		2,840,583		—			2,840,583
Total property and equipment, net		—		15,706		—			15,706
Investment in subsidiaries		876,154		—		(876,154	)		—
Total other long-term assets		44,291		53,247		—			97,538

Total assets	$	3,669,313	$	4,831,399	$	(5,329,627	)	$	3,171,085


LIABILITIES AND EQUITY
Accounts payable — related parties	$	790,251	$	3,663,513	$	(4,453,473	)	$	291
Other current liabilities		68,706		268,017		—			336,723
Other long-term liabilities		629,092		23,715		—			652,807
Long-term debt		845,836		—		—			845,836
Equity		1,335,428		876,154		(876,154	)		1,335,428

Total liabilities and equity	$	3,669,313	$	4,831,399	$	(5,329,627	)	$	3,171,085

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2010


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries			Total

Total operating revenues	$	—		$	240,496		$	—		$	240,496
Total operating costs and expenses		(64,846	)		(129,236	)		—			(194,082	)

Income (loss) from operations		(64,846	)		111,260			—			46,414
Interest expense		(12,036	)		—			—			(12,036	)
Other, net		107,739			(3,521	)		(107,739	)		(3,521	)

Income before income taxes		30,857			107,739			(107,739	)		30,857
Income tax expense		(10,082	)		—			—			(10,082	)

Net income	$	20,775		$	107,739		$	(107,739	)	$	20,775

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2009


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries			Total

Total operating revenues	$	—		$	153,494		$	��		$	153,494
Total operating costs and expenses		(9,083	)		(95,816	)		—			(104,899	)

Income (loss) from operations		(9,083	)		57,678			—			48,595
Interest expense		(6,809	)		—			—			(6,809	)
Other, net		57,478			(200	)		(57,478	)		(200	)

Income before income taxes		41,586			57,478			(57,478	)		41,586
Income tax expense		(21,824	)		—			—			(21,824	)

Net income	$	19,762		$	57,478		$	(57,478	)	$	19,762

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2010


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries			Total

Total operating revenues	$	—		$	668,206		$	—		$	668,206
Total operating costs and expenses		60,209			(352,972	)		—			(292,763	)

Income from operations		60,209			315,234			—			375,443
Interest expense		(34,293	)		—			—			(34,293	)
Other, net		311,336			(3,898	)		(311,336	)		(3,898	)

Income before income taxes		337,252			311,336			(311,336	)		337,252
Income tax expense		(124,766	)		—			—			(124,766	)

Net income	$	212,486		$	311,336		$	(311,336	)	$	212,486

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2009


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries			Total

Total operating revenues	$	—		$	366,828		$	—		$	366,828
Total operating costs and expenses		(86,376	)		(301,379	)		—			(387,755	)

Income (loss) from operations		(86,376	)		65,449			—			(20,927	)
Interest expense		(17,379	)		—			—			(17,379	)
Other, net		65,101			(348	)		(65,101	)		(348	)

Income (loss) before income taxes		(38,654	)		65,101			(65,101	)		(38,654	)
Income tax benefit		11,973			—			—			11,973

Net income (loss)	$	(26,681	)	$	65,101		$	(65,101	)	$	(26,681	)

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

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

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2009


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries		Total

Net cash flows provided by (used in) operating activities	$	(91,954	)	$	324,032		$	—	$	232,078
Net cash flows provided by (used in) investing activities		77,590			(319,468	)		—		(241,878	)
Net cash flows provided by (used in) financing activities		14,367			(6,624	)		—		7,743

Net increase (decrease) in cash and cash equivalents		3			(2,060	)		—		(2,057	)
Cash and cash equivalents at beginning of period .		—			17,752			—		17,752

Cash and cash equivalents at end of period .	$	3		$	15,692		$	—	$	15,695

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Note Q.Subsequent events

Marbob Acquisition.On July 19, 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 for aggregate consideration of (i) cash in the amount of $1.45 billion, (ii) the issuance by the Company to Marbob of an 8 percent unsecured promissory note due 2018 in the aggregate principal amount of $150 million 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 of third parties of contractual preferential rights to purchase certain interests in properties to be acquired from Marbob.

In October 2010, the Company closed the Marbob Acquisition. At closing, the Company paid approximately $1.1 billion in cash plus the unsecured promissory note and common stock described above for a total purchase price of approximately $1.3 billion. The total purchase price as originally announced was reduced due to third party contractual preferential rights to purchase certain of the interests in the Marbob properties. The Marbob Acquisition remains subject to certain post-closing adjustments. Certain of the third parties’ contractual preferential rights became subject to litigation, as discussed below. The Company funded the cash consideration in the Marbob Acquisition with borrowings under its Credit Facility and proceeds from the Private Placement.

Marbob preferential rights.Certain of the Marbob interests in properties contained contractual preferential rights to purchase 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 right to purchase interests 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 rights to purchase. BP and Apache contested Marbob’s ability to exercise its contractual preferential 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 rights. As a result of the settlement, we acquired a non-operated interest in substantially all of the oil and natural gas assets subject to the litigation for approximately $286 million. This acquisition remains subject to certain post-closing adjustments. The Company funded the acquisition with borrowings under its Credit Facility.

New commodity derivative contracts.In October 2010, the Company entered into the following oil price swaps to hedge additional amounts of its estimated future oil production:


	Aggregate		Index		Contract
	Volume		Price^(a)		Period

Oil (volumes in Bbls):
Price swap		378,000	$	85.62		1/1/11 - 6/30/11
Price swap		200,000	$	83.47		1/1/11 - 11/30/11
Price swap		2,568,000	$	85.98		1/1/11 - 12/31/11
Price swap		96,000	$	86.80		7/1/11 - 12/31/11
Price swap		540,000	$	86.84		1/1/12 - 6/30/12
Price swap		389,000	$	86.95		1/1/12 - 11/30/12
Price swap		1,914,000	$	87.58		1/1/12 - 12/31/12


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

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited

Note R.Supplementary information

Capitalized costs


	September 30,			December 31,
(in thousands)	2010			2009

*Oil and natural gas properties:*
Proved	$	3,647,441		$	3,139,424
Unproved		224,274			218,580
Less: accumulated depletion		(692,922	)		(517,421	)

Net capitalized costs for oil and natural gas properties	$	3,178,793		$	2,840,583

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


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2010		2009			2010		2009

Property acquisition costs:
Proved	$	3,762	$	(467	)	$	17,501	$	(1,475	)
Unproved		10,874		7,618			31,903		12,200
Exploration		74,740		26,065			136,673		111,005
Development		88,310		64,554			334,222		179,783

Total costs incurred for oil and natural gas properties	$	177,686	$	97,770		$	520,299	$	301,513


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


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2010		2009			2010			2009

Proved property acquisition costs	$	—	$	—		$	—		$	—
Exploration costs		321		(70	)		573			150
Development costs		197		309			(1,227	)		(2,418	)

Total	$	518	$	239		$	(654	)	$	(2,268	)

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

The following discussion is intended to assist in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated financial statements and notes, as well as the selected historical consolidated financial data and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2009.

During the fourth quarter of 2009, we closed the Wolfberry Acquisitions, as discussed below. The results of these acquisitions are included in our results of operations beginning January 1, 2010. As a result, many comparisons between periods will be difficult or impossible.

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

Overview

We are an independent oil and natural gas company engaged in the acquisition, development and exploration of producing oil and natural gas properties. Our core operations are primarily focused in the Permian Basin of Southeast New Mexico and West Texas. We have also acquired significant acreage positions in and are actively involved in the drilling or participating in drilling of emerging plays including the Bone Spring located in the Permian Basin of Southeast New Mexico and the Bakken play in the Williston Basin of North Dakota, where we are applying horizontal drilling, advanced fracture stimulation and enhanced recovery technologies. Crude oil comprised 67 percent of our 211.5 million barrels of oil equivalent (“MMBoe”) of estimated net proved reserves at December 31, 2009, and 68 percent of our 10.6 MMBoe of production for the nine months ended September 30, 2010. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 95.3 percent of our proved developed producing cash flows discounted to present value at 10 percent (“PV-10”) and 66.4 percent of our 3,960 gross wells at December 31, 2009. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and stimulation methods used.

Commodity Prices

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

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

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

	•		the overall global demand for oil; and

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

	§		the impact of any decline in the United States economy,

	§		weather conditions, and

	§		liquefied natural gas deliveries to the United States.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may 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 positions at September 30, 2010.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, oil prices were significantly higher during the comparable periods of 2010 measured against 2009, while natural gas prices were moderately higher. The following table sets forth the average NYMEX oil and natural gas prices for the three and nine months ended September 30, 2010 and 2009, as well as the high and low NYMEX prices for the same periods:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009

Average NYMEX prices:
Oil (Bbl)	$	76.09	$	68.24	$	77.60	$	57.22
Natural gas (MMBtu)	$	4.24	$	3.42	$	4.54	$	3.90

High and Low NYMEX prices:

*Oil (Bbl):*
High	$	82.55	$	74.37	$	86.84	$	74.37
Low	$	71.63	$	59.52	$	68.01	$	33.98

*Natural gas (MMBtu):*
High	$	4.92	$	4.88	$	6.01	$	6.07
Low	$	3.65	$	2.51	$	3.65	$	2.51

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $83.90 and $79.49 per Bbl and $4.04 and $3.29 per MMBtu, respectively, during the period from October 1, 2010 to November 2, 2010. At November 2, 2010, the NYMEX oil price and NYMEX natural gas price were $83.90 per Bbl and $3.87 per MMBtu, respectively.

Recent Events

Marbob acquisition.On July 19, 2010, we entered into an asset purchase agreement to acquire substantially all of the oil and natural gas leases, interests, properties and related assets owned by Marbob Energy Corporation and certain affiliates (“Marbob”) for aggregate consideration of (i) cash in the amount of $1.45 billion, (ii) our issuance to Marbob of an 8 percent unsecured promissory note due 2018 in the aggregate principal amount of $150 million and (iii) the issuance to Marbob of approximately 1.1 million shares of our common stock, subject to purchase price adjustments, which included downward purchase price adjustments based on the exercise of third parties of contractual preferential rights to purchase certain interests in properties to be acquired from Marbob.

The Marbob assets are primarily located in the Permian Basin of Southeast New Mexico, including a large acreage position contiguous to our core Yeso play on the Southeast New Mexico Shelf and a significant acreage position in the emerging Bone Spring play in Southeast New Mexico. These assets are a complement to our New Mexico Shelf position and significantly increase our Yeso drilling inventory. In addition, Marbob’s Bone Spring acreage, when coupled with our existing acreage, gives us a significant acreage position in one of the newest emerging plays in the industry and adds a significant new area of potential growth to our portfolio. We also retained most of Marbob’s experienced technical and operational staff.

In October 2010, we closed the Marbob acquisition. At closing, we paid approximately $1.1 billion in cash plus the unsecured promissory note and common stock described above for a total purchase price of approximately $1.3 billion. The total purchase price as originally announced was reduced due to third party contractual preferential rights to purchase certain of the interests in the Marbob properties. The Marbob acquisition remains subject to certain post-closing adjustments. Certain of the third parties’ contractual preferential rights became subject to litigation as discussed below. We funded the Marbob acquisition with borrowings under our credit facility and proceeds from the private placement, discussed later.

Marbob preferential rights.Certain of the Marbob interests in properties contained contractual preferential rights to purchase by third parties if Marbob were to sell them. Marbob informed us of its receipt of a notice from BP America Production Company (“BP”) electing to exercise its contractual preferential purchase right to purchase interests 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 rights to purchase. BP and Apache contested Marbob’s ability to exercise its contractual preferential rights in this situation. As a result, Marbob and we 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, we and Marbob resolved the litigation with BP and Apache related to the disputed contractual preferential rights. As a result of the settlement, we acquired a non-operated interest in substantially all the oil and natural gas assets subject to the litigation for approximately $286 million. This acquisition remains subject to certain post-closing adjustments. We funded the acquisition with borrowings under our credit facility.

Private placement of equity.On July 19, 2010, we entered into a common stock purchase agreement with certain third-party accredited investors to sell 6.6 million shares of our common stock at a price of $45.30 per share in a private placement for aggregate cash consideration of approximately $300 million. We paid approximately $7.3 million in transaction costs, which includes the placement agent fee. On October 7, 2010, we closed the private placement simultaneously with the closing of the Marbob acquisition.

Credit facility amendment .On October 7, 2010, we amended our credit facility simultaneously with the closing of the Marbob acquisition to increase the borrowing base from $1.2 billion to $2.0 billion. We paid our bank group approximately $23.6 million associated with the amendment to increase the borrowing base. Pro forma at September 30, 2010, after taking into account the closing of the Marbob acquisition, the resolution of the Marbob preferential right dispute, the closing of the credit facility amendment, the private placement and estimated related transaction costs, we estimate our outstanding indebtedness under our credit facility would have been approximately $1.5 billion and our availability under our credit facility would have been approximately $470 million.

2011 capital budget.In November 2010, we announced our 2011 capital budget of approximately $1.1 billion, which we expect can be funded substantially within our cash flow, based on current commodity prices and our expectations. As our size and financial flexibility have grown, we now take a longer-term view on spending substantially within our cash flow, and our spending during any specific period may exceed our cash flow for that period. However, our capital budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in our drilling and completion costs, we may reduce our capital spending program to be substantially within our cash flow.

Our capital budget does not include acquisitions (other than the customary purchase of leasehold acreage). The following is a summary of our 2011 capital budget:


	2011
(in millions)	Budget

Drilling and recompletion opportunities in our core operating area	$	736
Projects operated by third parties		68
Emerging plays, acquisition of leasehold acreage and other property interests, geological and geophysical and other		200
Facilities and other capital in our core operating areas		100

Total	$	1,104

Equity issuance.On February 1, 2010, we issued approximately 5.3 million shares of our common stock at $42.75 per share in a public offering. 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.

Wolfberry acquisitions.In December 2009, together with the acquisition of related additional interests that closed in 2010, we closed two acquisitions of interests in producing and non-producing assets in the Wolfberry play of the Permian Basin for approximately $270.7 million in cash (the “Wolfberry Acquisitions”). The Wolfberry Acquisitions were primarily funded with borrowings under our credit facility. Our 2009 results of operations do not include any production, revenues or costs from the Wolfberry Acquisitions.

2010 capital budget.In August 2010, we announced the increase of our 2010 capital budget to $700 million. After considering additional operations on assets acquired as a result of the Marbob acquisition and the Marbob preferential right dispute, we expect

2010 capital expenditures to total approximately $760 million, which does not include the costs of acquisitions other than customary leasehold purchases of leasehold acreage. Based on current commodity prices and our expectations, we believe our 2010 planned capital expenditures, excluding the effects of acquisitions, will exceed our 2010 cash flow. As our size and financial flexibility have grown, we now take a longer-term view on spending substantially within our cash flow, and our spending during any specific period may exceed our cash flow for that period. However, our capital expenditure plan is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in our drilling and completion costs, we may reduce our capital spending program to be substantially within our cash flow. The following is a summary of our 2010 capital budget and current 2010 planned capital expenditures:


			Current 2010
	2010		Planned Capital
(in millions)	Budget		Expenditures^(a)

Drilling and recompletion opportunities in our core operating area	$	538	$	592
Projects operated by third parties		10		10
Emerging plays, acquisition of leasehold acreage and other property interests, geological and geophysical and other		117		118
Facilities and other capital in our core operating areas		35		40

Total	$	700	$	760


(a)		Includes estimated planned capital expenditures on the assets acquired as a result of the Marbob acquisition and the Marbob preferential right dispute.

Derivative Financial Instruments

Derivative financial instrument exposure.At September 30, 2010, the fair value of our financial derivatives was a net asset of $0.6 million. All of our counterparties to these financial derivatives are a party to our credit facility and have their outstanding debt commitments and derivative exposures collateralized pursuant to our credit facility. Under the terms of our financial derivative instruments and their collateralization under our credit facility, we do not have exposure to potential “margin calls” on our financial derivative instruments. We currently have no reason to believe that our counterparties to these commodity derivative contracts are not financially viable. Our credit facility does not allow us to offset amounts we may owe a lender against amounts we may be owed related to our financial instruments with such party.

New commodity derivative contracts.During the nine months ended September 30, 2010, we entered into additional commodity derivative contracts to hedge a portion of our estimated future production. The following table summarizes information about these additional commodity derivative contracts for the nine months ended September 30, 2010.


	Aggregate		Index			Contract
	Volume		Price			Period

Oil (volumes in Bbls)
Price swap		670,000	$	83.72	^(a)		1/1/10 – 12/31/10
Price swap		195,000	$	76.85	^(a)		3/1/10 – 12/31/10
Price swap		1,463,000	$	88.63	^(a)		5/1/10 – 12/31/10
Price swap		3,714,000	$	85.15	^(a)		1/1/11 – 12/31/11
Price swap		3,573,000	$	88.56	^(a)		1/1/12 – 12/31/12
Price swap		261,000	$	82.50	^(a)		7/1/12 – 12/31/12
Price swap		1,380,000	$	82.58	^(a)		1/1/13 – 12/31/13
Price swap		1,248,000	$	83.94	^(a)		1/1/14 – 12/31/14
Price swap		600,000	$	84.50	^(a)		1/1/15 – 6/30/15

Natural gas (volumes in MMBtus):
Price swap		418,000	$	5.99	^(b)		2/1/10 – 12/31/10
Price swap		1,250,000	$	5.55	^(b)		3/1/10 – 12/31/10
Price swap		5,076,000	$	6.14	^(b)		1/1/11 – 12/31/11
Price swap		300,000	$	6.54	^(b)		1/1/12 – 12/31/12


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

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

In October 2010, we entered into the following oil price swaps to hedge additional amounts of our estimated future oil production:


	Aggregate		Index		Contract
	Volume		Price^(a)		Period

Oil (volumes in Bbls):
Price swap		378,000	$	85.62		1/1/11 – 6/30/11
Price swap		200,000	$	83.47		1/1/11 – 11/30/11
Price swap		2,568,000	$	85.98		1/1/11 – 12/31/11
Price swap		96,000	$	86.80		7/1/11 – 12/31/11
Price swap		540,000	$	86.84		1/1/12 – 6/30/12
Price swap		389,000	$	86.95		1/1/12 – 11/30/12
Price swap		1,914,000	$	87.58		1/1/12 – 12/31/12


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

Results of Operations

The following table sets forth summary information concerning our production results, average sales prices and operating costs and expenses for the three and nine months ended September 30, 2010 and 2009. The actual historical data in this table excludes results from the Wolfberry Acquisitions for periods prior to January 1, 2010.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009

Production and operating data:
Net production volumes:
Oil (MBbl)		2,656		1,912		7,163		5,430
Natural gas (MMcf)		7,460		5,753		20,393		16,122
Total (MBoe)		3,899		2,871		10,562		8,117

Average daily production volumes:
Oil (Bbl)		28,870		20,783		26,238		19,890
Natural gas (Mcf)		81,087		62,533		74,700		59,055
Total (Boe)		42,384		31,205		38,688		29,733

Average prices:
Oil, without derivatives (Bbl)	$	71.90	$	63.44	$	73.73	$	53.00
Oil, with derivatives (Bbl)^(a)	$	72.29	$	70.75	$	72.06	$	65.96
Natural gas, without derivatives (Mcf)	$	6.64	$	5.60	$	6.87	$	4.90
Natural gas, with derivatives (Mcf)^(a)	$	7.21	$	6.19	$	7.38	$	5.48
Total, without derivatives (Boe)	$	61.68	$	53.46	$	63.27	$	45.19
Total, with derivatives (Boe)^(a)	$	63.04	$	59.51	$	63.12	$	55.00

Operating costs and expenses per Boe:
Lease operating expenses and workover costs	$	5.70	$	4.81	$	6.07	$	5.74
Oil and natural gas taxes	$	5.86	$	4.05	$	5.50	$	3.63
Depreciation, depletion and amortization	$	15.88	$	19.10	$	16.08	$	19.46
General and administrative	$	3.86	$	4.43	$	4.37	$	4.76


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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2010			2009			2010			2009

Gain (loss) on derivatives not designated as hedges:
Cash (payments on) receipts from oil derivatives	$	1,034		$	13,971		$	(11,951	)	$	70,383
Cash receipts from natural gas derivatives		4,258			3,395			10,378			9,227
Cash payments on interest rate derivatives		(1,224	)		(1,241	)		(3,658	)		(2,020	)
Unrealized mark-to-market gain (loss) on commodity and interest rate derivatives		(70,175	)		(23,908	)		67,460			(172,025	)

Gain (loss) on derivatives not designated as hedges	$	(66,107	)	$	(7,783	)	$	62,229		$	(94,435	)

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010				2009		2010				2009
	West		Grayburg		Grayburg		West		Grayburg		Grayburg
	Wolfberry		Jackson		Jackson		Wolfberry		Jackson		Jackson
Production and operating data:
Net production volumes:
Oil (MBbl)		455		451		390		1,142		1,248		1,038
Natural gas (MMcf)		1,378		1,250		1,068		3,356		3,532		2,972
Total (MBoe)		684		660		568		1,701		1,837		1,533

Average prices:
Oil, without derivatives (Bbl)	$	73.45	$	71.87	$	64.89	$	75.55	$	73.80	$	53.54
Natural gas, without derivatives (Mcf)	$	6.91	$	7.20	$	5.89	$	7.19	$	7.32	$	5.09
Total, without derivatives (Boe)	$	62.70	$	62.82	$	55.62	$	64.89	$	64.23	$	46.12

Production costs per Boe:
Lease operating expenses including workovers	$	4.63	$	5.03	$	4.74	$	4.50	$	5.77	$	5.77
Oil and natural gas taxes	$	4.06	$	5.43	$	4.73	$	4.27	$	5.55	$	3.95

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

Oil and natural gas revenues.Revenue from oil and natural gas operations was $240.5 million for the three months ended September 30, 2010, an increase of $87.0 million (57 percent) from $153.5 million for the three months ended September 30, 2009. This increase was primarily due to increases in realized oil and natural gas prices and increased production (i) as a result of the Wolfberry Acquisitions and (ii) due to successful drilling efforts during 2009 and 2010. Specifically the:

	•		average realized oil price (excluding the effects of derivative activities) was $71.90 per Bbl during the three months ended September 30, 2010, an increase of 13 percent from $63.44 per Bbl during the three months ended September 30, 2009;

	•		total oil production was 2,656 MBbl for the three months ended September 30, 2010, an increase of 744 MBbl (39 percent) from 1,912 MBbl for the three months ended September 30, 2009;

	•		average realized natural gas price (excluding the effects of derivative activities) was $6.64 per Mcf during the three months ended September 30, 2010, an increase of 19 percent from $5.60 per Mcf during the three months ended September 30, 2009; and

	•		total natural gas production was 7,460 MMcf for the three months ended September 30, 2010, an increase of 1,707 MMcf (30 percent) from 5,753 MMcf for the three months ended September 30, 2009.

Production expenses.The following table provides the components of our total oil and natural gas production costs for the three months ended September 30, 2010 and 2009:


	Three Months Ended
	September 30,
	2010				2009
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe

Lease operating expenses	$	22,213	$	5.70	$	13,573	$	4.73
Taxes:
Ad valorem		2,195		0.56		954		0.33
Production		20,664		5.30		10,682		3.72
Workover costs		—		—		230		0.08

Total oil and natural gas production expenses	$	45,072	$	11.56	$	25,439	$	8.86

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

The lease operating expenses during the third quarter of 2009 include the benefit of approximately $2.3 million ($0.79 per Boe) related to an overestimate of costs in the prior periods.

Lease operating expenses were $22.2 million ($5.70 per Boe) for the three months ended September 30, 2010, an increase of $8.6 million (64 percent) from $13.6 million ($4.73 per Boe) for the three months ended September 30, 2009. The increase in lease operating expenses was primarily due to (i) our wells successfully drilled and completed in 2009 and 2010, (ii) additional interests acquired in the Wolfberry Acquisitions in December 2009 and (iii) the benefit of the overestimate of costs in periods prior to third quarter 2009 mentioned above. The increase in lease operating expenses per Boe was in part due to the benefit of the overestimate of costs in periods prior to third quarter 2009 mentioned above, offset in part by additional production from our wells successfully drilled and completed in 2009 and 2010 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 primarily associated with the Wolfberry Acquisitions and 2009 and 2010 drilling activity.

Production taxes per unit of production were $5.30 per Boe during the three months ended September 30, 2010, an increase of 42 percent from $3.72 per Boe during the three months ended September 30, 2009. The increase was related to the increase in commodity prices and our increase in oil and natural gas revenues related to increased volumes coupled with a $2.2 million ($0.56 per Boe) increase in production taxes related to prior period adjustments on one of our assets in our New Mexico Permian area. Over the same period, our per Boe prices (excluding the effects of derivatives) increased 15 percent.

Workover expenses were approximately $0.2 million for the three months ended September 30, 2009, which were primarily related to workovers in the New Mexico Permian area performed to restore production.

Exploration and abandonments expense.The following table provides a breakdown of our exploration and abandonments expense for the three months ended September 30, 2010 and 2009:


	Three Months Ended
	September 30,
(in thousands)	2010		2009

Geological and geophysical	$	449	$	2,120
Exploratory dry holes		—		474
Leasehold abandonments and other		3,176		182

Total exploration and abandonments	$	3,625	$	2,776

Our geological and geophysical expense, which primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, was $0.4 million and $2.1 million for the three months ended September 30, 2010 and 2009, respectively.

During the three months ended September 30, 2009, we wrote-off additional costs associated with a prior quarter unsuccessful exploratory well in our Texas Permian area.

For the three months ended September 30, 2010 and 2009, we recorded $3.2 million and $0.2 million, respectively, of leasehold abandonments, which were primarily related to non-core prospects in our New Mexico Permian and Texas Permian areas.

Depreciation, depletion and amortization expense.The following table provides components of our depreciation, depletion and amortization expense for the three months ended September 30, 2010 and 2009:


	Three Months Ended
	September 30,
	2010				2009
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe

Depletion of proved oil and natural gas properties	$	60,746	$	15.58	$	53,824	$	18.75
Depreciation of other property and equipment		766		0.20		624		0.22
Amortization of intangible asset — operating rights		388		0.10		387		0.13

Total depletion, depreciation and amortization	$	61,900	$	15.88	$	54,835	$	19.10


Oil price used to estimate proved oil reserves at period end	$	73.85			$	67.00
Natural gas price used to estimate proved natural gas reserves at period end	$	4.41			$	3.30

Depletion of proved oil and natural gas properties was $60.7 million ($15.58 per Boe) for the three months ended September 30, 2010, an increase of $6.9 million (13 percent) from $53.8 million ($18.75 per Boe) for the three months ended September 30, 2009. The increase in depletion expense was primarily due to capitalized costs associated with new wells that were successfully drilled and completed in 2009 and 2010 and the Wolfberry Acquisitions, and was offset in part by the increase in the oil and natural gas prices between the periods utilized to determine proved reserves. The decrease in depletion expense per Boe was primarily due to (i) the increase in the oil and natural gas prices between the periods utilized to determine proved reserves, (ii) the increase in proved reserves

from the successful 2009 and 2010 drilling of unproved properties and (iii) the increase in total proved reserves due to the new rules related to disclosures of oil and natural gas reserves issued by the United States Securities and Exchange Commission (the “SEC”).

On December 31, 2009, we adopted the new SEC rules related to disclosures of oil and natural gas reserves. As a result of these new SEC rules, we recorded an additional 13.6 MMBoe of proved reserves in 2009. We included the additional proved reserves in our depletion computation in the fourth quarter of 2009 and first three quarters of 2010. Our third quarter of 2010 depletion expense rate was $15.58 per Boe, which is lower than past quarters in part due to these additional proved reserves. In the future, making comparisons to prior periods as it relates to our depletion rate may be difficult as a result of these new SEC rules.

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

Impairment of long-lived assets.We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Due primarily to downward adjustments to the economically recoverable proved reserves associated with declines in commodity prices and well performance, we recognized a non-cash charge against earnings of $1.9 million during the three months ended September 30, 2010, which was primarily attributable to natural gas related properties in our New Mexico Permian area. For the three months ended September 30, 2009, we recognized a non-cash charge against earnings of $1.1 million, which was primarily attributable to a downward revision of proved reserves primarily related to a property in our New Mexico Permian area.

General and administrative expenses.The following table provides components of our general and administrative expenses for the three months ended September 30, 2010 and 2009:


	Three Months Ended
	September 30,
	2010						2009
				Per						Per
(in thousands, except per unit amounts)	Amount			Boe			Amount			Boe

General and administrative expenses — recurring	$	15,227		$	3.92		$	10,986		$	3.83
Non-recurring bonus paid to Henry Entities’ employees		121			0.03			2,369			0.83
Non-cash stock-based compensation — stock options		564			0.14			1,315			0.46
Non-cash stock-based compensation — restricted stock		2,588			0.66			1,233			0.43
Less: Third-party operating fee reimbursements		(3,455	)		(0.89	)		(3,188	)		(1.11	)

Total general and administrative expenses	$	15,045		$	3.86		$	12,715		$	4.44

General and administrative expenses were $15.0 million ($3.86 per Boe) for the three months ended September 30, 2010, an increase of $2.3 million (18 percent) from $12.7 million ($4.44 per Boe) for the three months ended September 30, 2009. The increase in general and administrative expenses was primarily due to (i) an increase in non-cash stock-based compensation for stock-based compensation awards and (ii) an increase in the number of employees and related personnel expenses to handle our increased activities, partially offset by (i) a single month of the non-recurring bonus due to the Henry Entities’ employees in the third quarter of 2010 and (ii) an increase in third-party operating fee reimbursements. 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 2009 and 2010 and (ii) additional production from our Wolfberry Acquisitions for which we added no administrative personnel.

In connection with the Henry Entities acquisition in July 2008, we agreed to pay certain of the Henry Entities’ former employees a predetermined bonus amount, in addition to the compensation we pay these employees, at each of the first and second anniversaries of the closing of the acquisition. Since these employees 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.

We earn reimbursements as operator of certain oil and natural gas properties in which we own interests. As such, we earned reimbursements of $3.5 million and $3.2 million during the three months ended September 30, 2010 and 2009, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations.

Loss on derivatives not designated as hedges.The following table sets forth the cash settlements and the non-cash mark-to-market adjustment for the derivative contracts not designated as hedges for the three months ended September 30, 2010 and 2009:


	Three Months Ended
	September 30,
(in thousands)	2010			2009

*Cash payments (receipts):*
Commodity derivatives — oil	$	(1,034	)	$	(13,971	)
Commodity derivatives — natural gas		(4,258	)		(3,395	)
Financial derivatives — interest		1,224			1,241

*Mark-to-market (gain) loss:*
Commodity derivatives — oil		79,815			12,821
Commodity derivatives — natural gas		(10,300	)		8,442
Financial derivatives — interest		660			2,645

Loss on derivatives not designated as hedges	$	66,107		$	7,783

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, 2010 and 2009:


	Three Months Ended
	September 30,
(dollars in thousands)	2010			2009

Interest expense	$	12,036		$	6,809

Weighted average interest rate		5.5	%		3.2	%

Weighted average debt balance	$	698,038		$	664,633

Income tax provisions.We recorded income tax expense of $10.1 million and $21.8 million for the three months ended September 30, 2010 and 2009, respectively. The effective income tax rate for the three months ended September 30, 2010 and 2009 was 32.7 percent and 52.5 percent, respectively. At September 30, 2010 and 2009, we estimate our annual effective tax rate to be approximately 37.0 percent and 31.0 percent, respectively, (which is discussed later in this document) and at June 30, 2010 and 2009 we estimated our annual effective tax rate to be 37.4 percent and 42.1 percent, respectively. The annual effective tax rate is determined by estimating the annual permanent tax differences and the annual pre-tax book income. Our estimates involve assumptions we believe to be reasonable at the time of the estimation. The three months ended September 30, 2010 and 2009 includes approximately $1.3 million of tax benefit and $8.9 million of tax expense, respectively, associated with the effects of the change in the six months ended June 30, 2010 and 2009 and nine months ended September 30, 2010 and 2009 estimated annual effective tax rates.

We expect to record an approximate $8 million charge to income tax expense in the fourth quarter of 2010 to increase the tax rate we have utilized to record our net deferred tax liability. This increase in tax rate is due to an increase in our overall blended statutory state income tax rate, which is a result of the assets acquired in the Marbob acquisition and the Marbob preferential right dispute being located in New Mexico where the state income tax rate is higher than in Texas.

Nine months ended September 30, 2010 Compared to Nine months ended September 30, 2009

Oil and natural gas revenues.Revenue from oil and natural gas operations was $668.2 million for the nine months ended September 30, 2010, an increase of $301.4 million (82 percent) from $366.8 million for the nine months ended September 30, 2009. This increase was primarily due to increases in realized oil and natural gas prices and increased production (i) as a result of the Wolfberry Acquisitions and (ii) due to successful drilling efforts during 2009 and 2010. Specifically the:

	•		average realized oil price (excluding the effects of derivative activities) was $73.73 per Bbl during the nine months ended September 30, 2010, an increase of 39 percent from $53.00 per Bbl during the nine months ended September 30, 2009;

	•		total oil production was 7,163 MBbl for the nine months ended September 30, 2010, an increase of 1,733 MBbl (32 percent) from 5,430 MBbl for the nine months ended September 30, 2009;

	•		average realized natural gas price (excluding the effects of derivative activities) was $6.87 per Mcf during the nine months ended September 30, 2010, an increase of 40 percent from $4.90 per Mcf during the nine months ended September 30, 2009; and

	•		total natural gas production was 20,393 MMcf for the nine months ended September 30, 2010, an increase of 4,271 MMcf (26 percent) from 16,122 MMcf for the nine months ended September 30, 2009.

Production expenses.The following table provides the components of our total oil and natural gas production costs for the nine months ended September 30, 2010 and 2009:


	Nine Months Ended
	September 30,
	2010				2009
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe

Lease operating expenses	$	60,928	$	5.77	$	45,867	$	5.65
Taxes:
Ad valorem		7,387		0.70		3,445		0.42
Production		50,717		4.80		26,047		3.21
Workover costs		3,188		0.30		663		0.08

Total oil and natural gas production expenses	$	122,220	$	11.57	$	76,022	$	9.36

Lease operating expenses were $60.9 million ($5.77 per Boe) for the nine months ended September 30, 2010, an increase of $15.1 million (33 percent) from $45.9 million ($5.65 per Boe) for the nine months ended September 30, 2009. The increase in lease operating expenses was primarily due to (i) our wells successfully drilled and completed in 2009 and 2010 and (ii) additional interests acquired in the Wolfberry Acquisitions in December 2009. The increase in lease operating expenses per Boe was primarily due to (i) our wells successfully drilled and completed in 2009 and 2010 and (ii) additional interests acquired in the Wolfberry Acquisitions in December 2009, offset in part by additional production from our wells successfully drilled and completed in 2009 and 2010 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 primarily associated with the Wolfberry Acquisitions and 2009 and 2010 drilling activity.

Production taxes per unit of production were $4.80 per Boe during the nine months ended September 30, 2010, an increase of 50 percent from $3.21 per Boe during the nine months ended September 30, 2009. The increase was directly related to the increase in commodity prices and our increase in oil and natural gas revenues related to increased volumes coupled with a $2.2 million ($0.21 per

Boe) increase in production taxes related to prior periods on one of our assets in our New Mexico Permian area. Over the same period, our per Boe prices (excluding the effects of derivatives) increased 40 percent.

Workover expenses were approximately $3.2 million and $0.7 million for the nine months ended September 30, 2010 and 2009, respectively. The 2010 amounts related primarily to increased workovers during the first two quarters of 2010 in our New Mexico Permian area due to work performed to restore production, whereas the 2009 amounts related primarily to workovers in our Texas Permian area.

Exploration and abandonments expense.The following table provides a breakdown of our exploration and abandonments expense for the nine months ended September 30, 2010 and 2009:


	Nine Months Ended
	September 30,
(in thousands)	2010		2009

Geological and geophysical	$	1,677	$	3,245
Exploratory dry holes		218		2,340
Leasehold abandonments and other		3,903		4,610

Total exploration and abandonments	$	5,798	$	10,195

Our geological and geophysical expense, which primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, was approximately $1.7 million and $3.2 million for the nine months ended September 30, 2010 and 2009, respectively.

During the nine months ended September 30, 2009, we wrote-off an unsuccessful exploratory well in our Arkansas emerging play and two unsuccessful exploratory wells in our Texas Permian area.

For the nine months ended September 30, 2010, we recorded $3.9 million of leasehold abandonments, which were primarily related to non-core prospects in our New Mexico Permian and Texas Permian areas. For the nine months ended September 30, 2009, we recorded approximately $4.6 million of leasehold abandonments, which related primarily to the write-off of four non-core prospects in our New Mexico Permian area and three non-core prospects in our Texas Permian area.

Depreciation, depletion and amortization expense.The following table provides components of our depreciation, depletion and amortization expense for the nine months ended September 30, 2010 and 2009:


	Nine Months Ended
	September 30,
	2010				2009
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe

Depletion of proved oil and natural gas properties	$	166,514	$	15.77	$	154,819	$	19.07
Depreciation of other property and equipment		2,168		0.21		1,998		0.25
Amortization of intangible asset — operating rights		1,162		0.10		1,168		0.14

Total depletion, depreciation and amortization	$	169,844	$	16.08	$	157,985	$	19.46


Oil price used to estimate proved oil reserves at period end	$	73.85			$	67.00
Natural gas price used to estimate proved natural gas reserves at period end	$	4.41			$	3.30

Depletion of proved oil and natural gas properties was $166.5 million ($15.77 per Boe) for the nine months ended September 30, 2010, an increase of $11.7 million (8 percent) from $154.8 million ($19.07 per Boe) for the nine months ended September 30, 2009. The increase in depletion expense was primarily due to capitalized costs associated with new wells that were successfully drilled and completed in 2009 and 2010 and the Wolfberry Acquisitions, and was offset in part by the increase in the oil and natural gas prices between the periods utilized to determine proved reserves. The decrease in depletion expense per Boe was primarily due to (i) the

increase in the oil and natural gas prices between the periods utilized to determine proved reserves, (ii) the increase in proved reserves from the successful 2009 and 2010 drilling of unproved properties and (iii) the increase in total proved reserves due to the new SEC rules related to disclosures of oil and natural gas reserves.

On December 31, 2009, we adopted the new SEC rules related to disclosures of oil and natural gas reserves. As a result of these new SEC rules, we recorded an additional 13.6 MMBoe of proved reserves in 2009. We included the additional proved reserves in our depletion computation in the fourth quarter of 2009 and first three quarters of 2010. Our depletion expense rate for the nine months ended September 30, 2010, was $15.77 per Boe, which is lower than the same period last year in part due to these additional proved reserves. In the future, making comparisons to prior periods as it relates to our depletion rate may be difficult as a result of these new SEC rules.

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

Impairment of long-lived assets.We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Due primarily to downward adjustments to the economically recoverable proved reserves associated with declines in commodity prices and well performance, we recognized a non-cash charge against earnings of $9.2 million during the nine months ended September 30, 2010, which was primarily attributable to natural gas related properties in our New Mexico Permian area. For the nine months ended September 30, 2009, we recognized a non-cash charge against earnings of $9.7 million, which was primarily attributable to non-core natural gas related properties in our New Mexico Permian area.

General and administrative expenses.The following table provides components of our general and administrative expenses for the nine months ended September 30, 2010 and 2009:


	Nine Months Ended
	September 30,
	2010						2009
				Per						Per
(in thousands, except per unit amounts)	Amount			Boe			Amount			Boe

General and administrative expenses — recurring	$	42,223		$	4.01		$	32,925		$	4.06
Non-recurring bonus paid to Henry Entities’ employees		5,059			0.48			7,680			0.95
Non-cash stock-based compensation — stock options		2,152			0.20			3,228			0.40
Non-cash stock-based compensation — restricted stock		6,702			0.63			3,433			0.42
Less: Third-party operating fee reimbursements		(9,995	)		(0.95	)		(8,633	)		(1.06	)

Total general and administrative expenses	$	46,141			4.37		$	38,633		$	4.77

General and administrative expenses were $46.1 million ($4.37 per Boe) for the nine months ended September 30, 2010, an increase of $7.5 million (19 percent) from $38.6 million ($4.77 per Boe) for the nine months ended September 30, 2009. The increase in general and administrative expenses was primarily due to (i) an increase in non-cash stock-based compensation for stock-based compensation awards and (ii) an increase in the number of employees and related personnel expenses to handle our increased activities, partially offset by (i) a decrease in the non-recurring bonus due to the Henry Entities employees (discussed in the next paragraph) and (ii) an increase in third-party operating fee reimbursements. 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 2009 and 2010 and (ii) additional production from our Wolfberry Acquisitions for which we added no administrative personnel.

We earn reimbursements as operator of certain oil and natural gas properties in which we own interests. As such, we earned reimbursements of $10.0 million and $8.6 million during the nine months ended September 30, 2010 and 2009, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations.

(Gain) loss on derivatives not designated as hedges.The following table sets forth the cash settlements and the non-cash mark-to-market adjustment for the derivative contracts not designated as hedges for the nine months ended September 30, 2010 and 2009:


	Nine Months Ended
	September 30,
(in thousands)	2010			2009

*Cash payments (receipts):*
Commodity derivatives — oil	$	11,951		$	(70,383	)
Commodity derivatives — natural gas		(10,378	)		(9,227	)
Financial derivatives — interest		3,658			2,020
*Mark-to-market (gain) loss:*
Commodity derivatives — oil		(40,926	)		156,920
Commodity derivatives — natural gas		(30,978	)		13,460
Financial derivatives — interest		4,444			1,645

(Gain) loss on derivatives not designated as hedges	$	(62,229	)	$	94,435

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, 2010 and 2009:


	Nine Months Ended
	September 30,
(dollars in thousands)	2010			2009

Interest expense	$	34,293		$	17,379

Weighted average interest rate		5.4	%		2.7	%

Weighted average debt balance	$	690,797		$	666,864

In September 2009, we refinanced $300 million of our credit facility debt with 8.625 percent unsecured senior notes. The increase in our weighted average interest rate and the increase in interest expense of approximately $16.9 million was primarily due to the higher interest rate on the unsecured senior notes. The increase in the weighted average debt balance during the nine months ended September 30, 2010 is due, in part, to our borrowings under our credit facility to finance the Wolfberry Acquisitions, offset by a partial repayment on our credit facility in February 2010 with the net proceeds of our equity offering.

Income tax provisions.We recorded income tax expense of $124.8 million and an income tax benefit of $12.0 million for the nine months ended September 30, 2010 and 2009, respectively. The effective income tax rate for the nine months ended September 30, 2010 and 2009 was 37.0 percent and 31.0 percent, respectively. The lower annual effective tax rate in 2009 compared to 2010 is primarily due to the estimated annual 2010 and 2009 permanent tax differences compared to the related current estimated annual pre-tax book income. The estimated annual effective tax rate for 2010 and 2009 at June 30, 2010 and 2009 was 37.0 percent and 42.1 percent, respectively, based on the then estimated 2010 and 2009 annual permanent tax differences and pre-tax book income. Depending on the levels of estimated permanent differences and annual pre-tax book income and changes in those amounts between quarters can significantly alter our estimated effective tax rates between periods.

Capital Commitments, Capital Resources and Liquidity

Capital commitments.Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, financing under our credit facility, proceeds from the disposition of assets or alternative financing sources, as discussed in “Capital resources” below.

Oil and natural gas properties.Our costs incurred on oil and natural gas properties, excluding acquisitions and asset retirement obligations, during the nine months ended September 30, 2010 and 2009 totaled $471.5 million and $293.1 million, respectively, as compared to the comparable amount in cash flows used by investing activities of $486.9 million and $316.8 million for the respective periods. The primary reason for the differences in the costs incurred and cash flow expenditures is the timing of payments. These expenditures in 2010 were significantly funded by cash flow from operations (including effects of cash settlements received from (paid on) derivatives not designated as hedges) and to a lesser extent from borrowing under our credit facility.

In August 2010, we announced an increase of our 2010 capital budget to $700 million. At the present, we expect our 2010 planned capital expenditures to be approximately $760 million, which excludes acquisitions (other than the customary purchase of leasehold acreage) and includes approximately $57 million of capital expenditures planned for the fourth quarter of 2010 on the properties acquired in the Marbob acquisition and the Marbob preferential right dispute. Based on current commodity prices and our expectations, we believe our 2010 planned capital expenditures will exceed our 2010 cash flow. Originally, our capital budget was front-end loaded, and we expected to outspend our cash flow in the first half of 2010. We outspent our after-tax operating cash flow during the nine months ended September 30, 2010 by over $65 million, excluding acquisitions. As our size and financial flexibility have grown, we now take a longer-term view on spending substantially within our cash flow, and our spending during any specific period may exceed our cash flow for that period. However, our capital budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in our drilling and completion costs, we may reduce our capital spending program to be substantially within our cash flow.

In October 2010, we closed the Marbob acquisition and settled our Marbob preferential right dispute. For additional information see “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent events.”

In October 2010, we announced our plans to divest certain Permian Basin assets which are generally not in our core areas and which have higher per unit lifting costs than our average portfolio of assets. Our current expectation is that if we are able to successfully divest of these assets, the proceeds from this divesture would be over $100 million and that we would close before the end of 2010.

In November 2010, we announced our 2011 capital budget of approximately $1.1 billion, which we expect can be funded substantially within our cash flow, based on current commodity prices and our expectations. As our size and financial flexibility have grown, we now take a longer-term view on spending substantially within our cash flow, and our spending during any specific period may exceed our cash flow for that period. However, our capital budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in our drilling and completion costs, we may reduce our capital spending program to be substantially within our cash flow.

Other than the purchase of leasehold acreage, our current 2010 capital expenditure plan and 2011 capital budget is exclusive of acquisitions. We do not have a specific acquisition budget, since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek to acquire oil and natural gas properties that provide opportunities for the addition of reserves and production through a combination of development, high-potential exploration and control of operations that will allow us to apply our operating expertise.

Although we cannot provide any assurance, we 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.

Acquisitions.Our expenditures for acquisitions of proved and unproved properties (which includes customary leasehold acreage acquisitions) during the three months ended September 30, 2010 and 2009 totaled approximately $14.6 million and $7.2 million, respectively, and approximately $49.4 million and $10.7 million during the nine months ended September 30, 2010 and 2009,

respectively. The acquisitions of proved properties during the nine months ended September 30, 2010, primarily relate to additional interests that we closed in 2010 on the Wolfberry Acquisitions and the acquisition of other Wolfberry assets.

Contractual obligations.Our contractual obligations include long-term debt, cash interest expense on debt, operating lease obligations, drilling commitments, employment agreements with executive officers, contractual bonus payments, derivative liabilities and other obligations. Since December 31, 2009, the material changes in our contractual obligations included a $157.5 million decrease in outstanding long-term borrowings, a $23.4 million decrease in cash interest expense on debt and our net commodity derivative is now in an asset position of approximately $0.6 million. However, subsequent to September 30, 2010, our debt substantially increased as a result of the closing of the Marbob acquisition and the Marbob preferential right dispute. See Note J of Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our long-term debt and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for information regarding the interest on our long-term debt and information on changes in the fair value of our open derivative obligations during the nine months ended September 30, 2010.

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

Capital resources.Our primary sources of liquidity have been cash flows generated from operating activities (including the cash settlements received from (paid on) derivatives not designated as hedges presented in our investing activities) and financing provided by our credit facility. We believe that our cash flows may not be adequate to meet both our short-term working capital requirements and our current 2010 capital expenditure plans (excluding the Marbob acquisition and the Marbob preferential right dispute). We believe we have adequate availability under our credit facility to fund cash flow deficits, though we could reduce our capital spending program to remain substantially within our cash flow.

Cash flow from operating activities.Our net cash provided by operating activities was $402.8 million and $232.1 million for the nine months ended September 30, 2010 and 2009, respectively. The increase in operating cash flows during the nine months ended September 30, 2010 over the same period in 2009 was principally due to increases in average realized oil and natural gas prices coupled with increased production.

Cash flow used in investing activities.During the nine months ended September 30, 2010 and 2009, we invested $504.6 million and $316.8 million, respectively, for additions to, and acquisitions of, oil and natural gas properties, inclusive of dry hole costs. Cash flows used in investing activities were higher during the nine months ended September 30, 2010 over 2009, due to the Wolfberry Acquisitions and an increase in our capital expenditures on oil and natural gas properties, offset by settlements paid on derivatives not designated as hedges during the nine months ended September 30, 2010 as compared to receipts on derivatives not designated as hedges in the comparable period in 2009.

Cash flow from financing activities.Net cash provided by financing activities was $107.2 million and $7.7 million for the nine months ended September 30, 2010 and 2009, respectively. During the nine months ended September 30, 2010, we reduced our outstanding balance on our credit facility by $157.5 million primarily using proceeds from the issuance of common stock. During the nine months ended September 30, 2009, we had net borrowings of $15.7 million under our credit facility.

Our credit facility, as amended, has a maturity date of July 31, 2013. At September 30, 2010, we had letters of credit outstanding under the credit facility of approximately $25,000, and our availability to borrow additional funds was approximately $807.5 million based on the borrowing base of $1.2 billion. On October 7, 2010, in connection with the closing of the Marbob acquisition, we entered into an amendment to our credit facility to increase the borrowing base from $1.2 billion to $2.0 billion, as further discussed below. The next scheduled borrowing base redetermination will be in April 2011. Between scheduled borrowing base redeterminations, we and, if requested by 66 2/3 percent of the lenders, the lenders, may each request one special redetermination.

Advances on the credit facility bear interest, at our option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) (3.25 percent at September 30, 2010) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). At September 30, 2010, the interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest margins ranging from 200 to 300 basis points and 112.5 to 212.5 basis points, respectively, per annum depending on the debt balance outstanding. At September 30, 2010, we paid commitment fees on the unused portion of the available borrowing base of 50 basis points per annum.

On July 19, 2010, we entered into a common stock purchase agreement with certain third-party accredited investors to sell 6.6 million shares of our common stock at a price of $45.30 per share in a private placement for aggregate cash consideration of approximately $300 million. We paid approximately $7.3 million of transaction costs, including a placement agent fee. On October 7, 2010, we closed the private placement simultaneously with the closing of the Marbob acquisition.

On October 7, 2010, we amended our credit facility simultaneously with the closing of the Marbob acquisition to increase the borrowing base from $1.2 billion to $2.0 billion. We paid our bank group, now a total of 34 banks, approximately $23.6 million associated with the amendment and for the previous commitments to increase the borrowing base. Pro forma at September 30, 2010, after taking into account the closing of the Marbob acquisition, the resolution of the Marbob preferential right dispute, the closing of the credit facility amendment, the private placement and estimated related transaction costs, we estimate our outstanding indebtedness under our credit facility would have been approximately $1.5 billion and our availability under our credit facility would have been approximately $470 million.

In conducting our business, we may utilize various financing sources, including the issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock, (iv) common stock and (v) other securities. We may also sell assets and issue securities in exchange for oil and natural gas assets or interests in oil and natural gas companies. Additional securities may be of a class senior to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined from time to time by our board of directors. Utilization of some of these financing sources may require approval from the lenders under our credit facility.

On February 1, 2010, we issued approximately 5.3 million shares of our common stock at $42.75 per share in a public offering. 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 borrowing under our credit facility.

Financial markets.The current state of the financial markets remains uncertain; however, we have recently seen improvements in the stock market, and the credit markets appear to have stabilized. There have been financial institutions that have (i) failed and been forced into government receivership, (ii) received government bail-outs, (iii) declared bankruptcy, (iv) been forced to seek additional capital and liquidity to maintain viability or (v) merged. The United States and world economies have experienced and continue to experience volatility, which continues to impact the financial markets.

At September 30, 2010, we had $807.5 million of available borrowing capacity. Pro forma at September 30, 2010, after taking into account the closing of the Marbob acquisition, the resolution of the Marbob preferential right dispute, the closing of the credit facility amendment, the private placement and estimated related transaction costs, we estimate our outstanding indebtedness under our credit facility would have been approximately $1.5 billion and our availability under our credit facility would have been approximately $470 million. Our credit facility is backed by a large syndicate of banks. Even in light of the volatility in the financial markets, we believe that the lenders under our credit facility have the ability to fund additional borrowings we may need for our business.

We pay floating rate interest under our credit facility, and we are unable to predict, especially in light of the uncertainty in the financial markets, whether we will incur increased interest costs due to rising interest rates. We have used interest rate derivatives to mitigate the cost of rising interest rates, and we may enter into additional interest rate derivatives in the future. Additionally, we may issue additional fixed rate debt in the future to increase available borrowing capacity under our credit facility, to extend the maturity of some of our indebtedness or to reduce our exposure to the volatility of interest rates.

In the current financial markets, there is no assurance that we could refinance our credit facility with comparable terms. Because our credit facility matures in July 2013, we do not expect to seek refinancing of our credit facility any earlier than 2011.

To the extent we need additional funds beyond those available under our credit facility to operate our business or make acquisitions, we would have to pursue other financing sources. These sources could include issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock, (iv) common stock or (v) other securities. We may also sell assets. However, in light of the current financial market conditions there are no assurances that we could obtain additional funding, or if available, at what cost and terms.

Liquidity.Our principal sources of short-term liquidity are cash on hand and available borrowing capacity under our credit facility. At September 30, 2010, we had $0.4 million of cash on hand.

At September 30, 2010, we had $807.5 million of available borrowing capacity. Pro forma at September 30, 2010, after taking into account the closing of the Marbob acquisition, the resolution of the Marbob preferential right dispute, the private placement and estimated related transaction costs, our outstanding indebtedness under our credit facility would have been approximately $1.5 billion and availability under our credit facility would have been approximately $471 million. Our borrowing base is redetermined semi-annually. The next scheduled borrowing base redetermination will be in April 2011. Between scheduled borrowing base redeterminations, we and, if requested by 66 2/3 percent of the lenders, the lenders, may each request one special redetermination. In general, redeterminations are based upon a number of factors, including commodity prices and reserve levels. Upon a redetermination, our

borrowing base could be substantially reduced. In light of the current volatility in commodity prices and the state of the financial markets, there is no assurance that our borrowing base will not be reduced.

Book capitalization and current ratio.Our book capitalization at September 30, 2010 was $2.5 billion, consisting of debt of $688.6 million and stockholders’ equity of $1.8 billion. Our debt to book capitalization was 28 percent and 39 percent at September 30, 2010 and December 31, 2009, respectively. Our ratio of current assets to current liabilities was 0.69 to 1.0 at September 30, 2010 as compared to 0.64 to 1.0 at December 31, 2009.

At September 30, 2010, after taking into account the closing of the Marbob acquisition and the Marbob preferential right dispute, the closing of the amendment to the credit facility, the private placement and estimated related transaction costs, we estimate our debt to book capitalization to be approximately 48 percent.

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, 2010, we received an average of $73.73 per barrel of oil and $6.87 per Mcf of natural gas before consideration of commodity derivative contracts compared to $53.00 per barrel of oil and $4.90 per Mcf of natural gas in the nine months ended September 30, 2009. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and continued through the first six months of 2008, commodity prices for oil and natural gas increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends have put pressure not only on our operating costs but also on capital costs. We expect these costs to reflect upward pressure during 2010 and 2011 as a result of the recent improvements in oil prices from 2009.

Critical Accounting Policies, Practices and Estimates

Our historical consolidated financial statements and related notes to consolidated financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to us.

In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are revenue recognition, the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets and valuation of stock-based compensation. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates, as additional information becomes known.

There have been no material changes in our critical accounting policies and procedures during the nine months ended September 30, 2010. See our disclosure of critical accounting policies in the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 26, 2010.

Recent Accounting Pronouncements

Various topics.In February 2010, the FASB issued an update to various topics, which eliminated outdated provisions and inconsistencies in the Accounting Standards Codification (the “Codification”), and clarified certain guidance to reflect the FASB’s original intent. The update is effective for the first reporting period, including interim periods, beginning after issuance of the update, except for the amendments affecting embedded derivatives and reorganizations. In addition to amending the Codification, the FASB made corresponding changes to the legacy accounting literature to facilitate historical research. These changes are included in an appendix to the update. We adopted the update effective January 1, 2010, and the adoption did not have a significant impact on our consolidated financial statements.

Accounting for extractive activities.In April 2010, the FASB issued an amendment to a paragraph in the accounting standard for oil and natural gas extractive activities accounting. The standard adds to the Codification the SEC’sModernization of Oil and Gas Reportingrelease. We adopted the update effective April 20, 2010, and the adoption did not have a significant impact on our consolidated financial statements.

Accounting for leases.In August 2010, the FASB issued an Exposure Draft proposing a new approach to lease accounting so that lessors and lessees present relevant, faithfully representative information about the rights and obligations arising from leases that assists users of financial statements in their assessment of the amounts, timing and uncertainty of the cash flows arising from leases.

The existing accounting models for leases require lessees to classify their leases as either capital leases or operating leases. However, those models have been criticized for failing to meet the needs of users of financial statements because they do not provide a faithful representation of leasing transactions. In particular, they omit relevant information about rights and obligations that meet the definitions of assets and liabilities in the boards’ conceptual framework. The models also lead to a lack of comparability and undue complexity because of the sharp ‘bright-line’ distinction between capital leases and operating leases. As a result, many users of financial statements adjust the amounts presented in the statement of financial position to reflect the assets and liabilities arising from operating leases.

Accordingly, the FASB and the International Accounting Standards Board initiated a joint project to develop a new approach to lease accounting that would ensure that assets and liabilities arising under leases are recognized in the statement of financial position.

Currently, we lease vehicles, equipment and office facilities under non-cancellable operating leases. If the Exposure Draft were to become a standard, we would no longer report lease payments in the consolidated statements of operations, and we would capitalize these leases on our consolidated balance sheets and depreciate them over their useful lives. We are currently evaluating the impact on our consolidated financial statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2009.

We are exposed to a variety of market risks including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we are a party at September 30, 2010, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit. We do not enter into derivative or other financial instruments for speculative or trading purposes.

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

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

Commodity price risk.We are exposed to market risk as the prices of oil and natural gas are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of oil and natural gas we have entered into, and may in the future enter into, additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a specified 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, 2010, would have created a net unrealized loss of approximately $165.3 million on our commodity price risk management contracts held at September 30, 2010.

At September 30, 2010, we had (i) oil price swaps that settle on a monthly basis covering future oil production from July 1, 2010 through June 30, 2015 and (ii) a natural gas price swap, natural gas price collars and natural gas basis swaps covering future natural gas production from July 1, 2010 to December 31, 2012. See Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on our commodity derivative contracts. The average NYMEX oil price and average NYMEX natural gas price for the nine months ended September 30, 2010, was $77.60 per Bbl and $4.54 per MMBtu, respectively. At November 2, 2010, the NYMEX oil price and NYMEX natural gas price were $83.90 per Bbl and $3.87 per MMBtu, respectively. A decrease in oil and natural gas prices would increase the fair value asset of our commodity derivative contracts from their recorded balance at September 30, 2010. Changes in the recorded fair value of the undesignated commodity derivative contracts are marked-to-market through earnings as unrealized gains or losses. The potential increase in our fair value asset would be recorded in earnings as an unrealized gain. However, an increase in the average NYMEX oil and natural gas prices above those at September 30, 2010, would result in a decrease in our 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. To reduce our exposure to changes in interest rates we have entered into, and may in the future enter into additional interest rate risk management arrangements for a portion of our outstanding debt. The agreements that we have entered into generally have the effect of providing us with a fixed interest rate for a portion of our variable rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We are exposed to changes in interest rates as a result of our credit facility, and the terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available borrowing base.

At September 30, 2010, we had interest rate swaps on $300 million of notional principal that fixed the LIBOR interest rate (not including the interest rate margins discussed above) at 1.90 percent for the three years beginning in May 2009. An average decrease

in future interest rates of 25 basis points from the future rate at September 30, 2010, would have increased our net unrealized liability on our interest rate risk management contracts by approximately $1.2 million.

We had total indebtedness of $392.5 million outstanding under our credit facility at September 30, 2010. The impact of a 1 percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $3.9 million.

The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method during 2010. During 2010, we were party to commodity and interest rate derivative instruments. See Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the nine months ended September 30, 2010:


	Derivative Instruments Net Assets (Liabilities)^(a)
(in thousands)	Commodities			Interest Rate			Total

Fair value of contracts outstanding at December 31, 2009	$	(64,332	)	$	(2,501	)	$	(66,833	)
Changes in fair values^(b)		70,331			(8,102	)		62,229
Contract maturities		1,573			3,658			5,231

Fair value of contracts outstanding at September 30, 2010	$	7,572		$	(6,945	)	$	627


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

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at September 30, 2010 at the reasonable assurance level.

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

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the other information set forth in this Report, you should carefully consider the risks discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, under the headings “Item 1. Business — Competition, Marketing Arrangements and Applicable Laws and Regulations,” “Item 1A. Risk Factors” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” which risks could materially affect the Company’s business, financial condition or future results. Except for the risk factor set forth below, there have been no material changes in the Company’s risk factors from those described in its Annual Report on Form 10-K for the year ended December 31, 2009, and “Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the six months ended June 30, 2010.

The risk factor below is intended to replace the risk factor in our Annual Report on Form 10-K for the year ended December 31, 2009 entitled “Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.”

We have substantial indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

We have incurred debt amounting to approximately $688.6 million as of September 30, 2010. At September 30, 2010, the borrowing base under our credit facility was $1.2 billion. At September 30, 2010, we had $807.5 million of available borrowing capacity. On October 7, 2010, in connection with the closing of the Marbob acquisition, we entered into an amendment to our credit facility to increase the borrowing base from $1.2 billion to $2.0 billion. Pro forma at September 30, 2010, after taking into account the closing of the Marbob acquisition, the resolution of the Marbob preferential right dispute, the closing of the credit facility amendment, the private placement and estimated related transaction costs, we estimate our outstanding indebtedness under our credit facility would have been approximately $1.5 billion and our availability under our credit facility would have been approximately $470 million.

As a result of our indebtedness, we will need to use a portion of our cash flow to pay interest, which will reduce the amount we will have available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Our indebtedness under our credit facility is at a variable interest rate, and so a rise in interest rates will generate greater interest expense to the extent we do not have applicable interest rate fluctuation hedges. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.

We may incur substantially more debt in the future. The indentures governing our outstanding 8.625 percent unsecured senior notes due 2017 contain restrictions on our incurrence of additional indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness under the indentures.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets or sell additional shares of common stock on terms that we may not find attractive if it may be done at all. Further, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under that indebtedness, which could adversely affect our business, financial condition and results of operations.

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

Total number

Maximum

of shares

number of

purchased as

shares that

Total number

part of publicly

may yet be

of shares

Average price

announced

purchased

Period

withheld⁽¹⁾

per share

plans

under the plan

July 1, 2010 - July 31, 2010

—

August 1, 2010 - August 31, 2010

1,322

58.19

—

September 1, 2010 - September 30, 2010

2,055

63.54

—


⁽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 6. Exhibits


Exhibit
Number		Exhibit
2.1 *		Asset Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc., Marbob Energy Corporation, Pitch Energy Corporation, Costaplenty Energy Corporation and John R. Gray, LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on July 20, 2010, and incorporated herein by reference).

3.1		Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).

3.2		Amended and Restated Bylaws of Concho Resources Inc., as amended March 25, 2008 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on March 26, 2008, and incorporated herein by reference).

4.1		Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Current Report on Form S-1/A on July 5, 2007, and incorporated herein by reference).

10.1		Common Stock Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc. and the purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on July 20, 2010, and incorporated herein by reference).

10.2		Indemnification Agreement, dated September 24, 2010, between Concho Resources Inc. and Don McCormack (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 29, 2010, and incorporated herein by reference).

10.3		Registration Rights Agreement, dated October 7, 2010, by and between Concho Resources Inc. and the purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on October 13, 2010, and incorporated herein by reference).

10.4		Fourth Amendment to Amended and Restated Credit Agreement, dated October 7, 2010, among Concho Resources Inc. and the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on October 13, 2010, and incorporated herein by reference).

10.5 (a)		Promissory Note in the principal amount of $150,000,000 between Concho Resources Inc. and Pitch Energy Corporation, dated October 7, 2010.

31.1 (a)		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 (a)		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 (b)		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 (b)		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS (a)		XBRL Instance Document.

101.SCH (a)		XBRL Schema Document.

101.CAL (a)		XBRL Calculation Linkbase Document.

101.DEF (a)		XBRL Definition Linkbase Document.

101.LAB (a)		XBRL Labels Linkbase Document.

101.PRE (a)		XBRL Presentation Linkbase Document.


(a)		Filed herewith.

(b)		Furnished herewith.

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

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 4, 2010	By	/s/ Timothy A. Leach Timothy A. Leach
		Director, Chairman of the Board of Directors, Chief Executive
		Officer and President (Principal Executive Officer)

	By	/s/ Darin G. Holderness Darin G. Holderness
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

	By	/s/ Don O. McCormack

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

EXHIBIT INDEX


Exhibit
Number		Exhibit
2.1 *		Asset Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc., Marbob Energy Corporation, Pitch Energy Corporation, Costaplenty Energy Corporation and John R. Gray, LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on July 20, 2010, and incorporated herein by reference).

3.1		Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).

3.2		Amended and Restated Bylaws of Concho Resources Inc., as amended March 25, 2008 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on March 26, 2008, and incorporated herein by reference).

4.1		Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Current Report on Form S-1/A on July 5, 2007, and incorporated herein by reference).

10.1		Common Stock Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc. and the purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on July 20, 2010, and incorporated herein by reference).

10.2		Indemnification Agreement, dated September 24, 2010, between Concho Resources Inc. and Don McCormack (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 29, 2010, and incorporated herein by reference).

10.3		Registration Rights Agreement, dated October 7, 2010, by and between Concho Resources Inc. and the purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on October 13, 2010, and incorporated herein by reference).

10.4		Fourth Amendment to Amended and Restated Credit Agreement, dated October 7, 2010, among Concho Resources Inc. and the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on October 13, 2010, and incorporated herein by reference).

10.5 (a)		Promissory Note in the principal amount of $150,000,000 between Concho Resources Inc. and Pitch Energy Corporation, dated October 7, 2010.

31.1 (a)		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 (a)		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 (b)		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 (b)		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS (a)		XBRL Instance Document.

101.SCH (a)		XBRL Schema Document.

101.CAL (a)		XBRL Calculation Linkbase Document.

101.DEF (a)		XBRL Definition Linkbase Document.

101.LAB (a)		XBRL Labels Linkbase Document.

101.PRE (a)		XBRL Presentation Linkbase Document.


(a)		Filed herewith.

(b)		Furnished herewith.

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

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg


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		40
Item 3.Quantitative and Qualitative Disclosures About Market Risk		60
Item 4.Controls and Procedures		61
PART II – OTHER INFORMATION		62
Item 1.Legal Proceedings		62
Item 1A.Risk Factors		62
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds		63
Item 6.Exhibits		64
EX-10.5
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

Concho Resources (CXO) 10-Q2010 Q3 Quarterly report

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