Concho Resources (CXO) 10-Q 2009 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, 2009

or

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

For the transition period from                    to                    

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)

Delaware	76-0818600
(State or other jurisdiction	(I.R.S. Employer
of incorporation or organization)	Identification No.)
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). Yeso 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.

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, 2009: 85,784,691 shares.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION	iii
Item 1.Consolidated Financial Statements (Unaudited)	iii
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations		42
Item 3.Quantitative and Qualitative Disclosures About Market Risk		63
Item 4.Controls and Procedures		65
PART II — OTHER INFORMATION		66
Item 1.Legal Proceedings		66
Item 1A.Risk Factors		66
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds		66
Item 6.Exhibits		67
EX-31.1
EX-31.2
EX-32.1
EX-32.2

i

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

     This report may contain 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”) that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and in our Annual Report on Form 10-K for the year ended December 31, 2008 and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009, could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

     Forward-looking statements may include statements about:

• our business and financial strategy;

• the estimated quantities of oil and natural gas reserves;

• our use of industry technology;

• our realized oil and natural gas prices;

• the timing and amount of the future production of our oil and natural gas;

• the amount, nature and timing of our capital expenditures;

• the drilling of our wells;

• our competition and government regulations;

• the marketing of our oil and natural gas;

• our exploitation activities or property acquisitions;

• the costs of exploiting and developing our properties and conducting other operations;

• general economic and business conditions;

• our cash flow and anticipated liquidity;

• uncertainty regarding our future operating results;

• our plans, objectives, expectations and intentions contained in this report that are not historical; and

• our ability to integrate acquisitions.

     You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this report. We do not undertake any obligation to release publicly any revisions to any forward-looking statements to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events, except as required by law.

     Although we believe that our plans, objectives, expectations and intentions reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that they will be achieved. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

ii

PART I — FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

Consolidated Balance Sheets at September 30, 2009 and December 31, 2008	1
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2009 and 2008	2
Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2009	3
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008	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)	2009			2008
Assets
Current assets:
Cash and cash equivalents	$	15,695		$	17,752
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas		67,021			48,793
Joint operations and other		72,402			92,833
Related parties		138			314
Derivative instruments		9,405			113,149
Deferred income taxes		5,800			—
Prepaid costs and other		8,462			5,942
Total current assets		178,923			278,783
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		2,980,268			2,693,574
Accumulated depletion		(468,247	)		(306,990	)
Total oil and natural gas properties, net		2,512,021			2,386,584
Other property and equipment, net		16,151			14,820
Total property and equipment, net		2,528,172			2,401,404
Deferred loan costs, net		21,982			15,701
Inventory		24,351			19,956
Intangible asset, net — operating rights		36,909			37,768
Noncurrent derivative instruments		30,727			61,157
Other assets		462			434
Total assets	$	2,821,526		$	2,815,203
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	12,010		$	7,462
Related parties		793			312
Other current liabilities:
Bank overdrafts		2,810			9,434
Revenue payable		40,532			22,286
Accrued and prepaid drilling costs		120,726			154,196
Derivative instruments		23,158			1,866
Deferred income taxes		—			37,205
Other current liabilities		42,204			38,057
Total current liabilities		242,233			270,818
Long-term debt		645,747			630,000
Noncurrent derivative instruments		16,559			—
Deferred income taxes		591,029			573,763
Asset retirement obligations and other long-term liabilities		13,258			15,468
Commitments and contingencies (Note K)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 85,605,502 and 84,828,824 shares issued at September 30, 2009 and December 31, 2008, respectively		86			85
Additional paid-in capital		1,023,543			1,009,025
Retained earnings		289,488			316,169
Treasury stock, at cost; 12,380 and 3,142 shares at September 30, 2009 and December 31, 2008, respectively		(417	)		(125	)
Total stockholders’ equity		1,312,700			1,325,154
Total liabilities and stockholders’ equity	$	2,821,526		$	2,815,203

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

1

Concho Resources Inc.

Consolidated Statements of Operations
Unaudited

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except per share amounts)	2009			2008			2009			2008
Operating revenues:
Oil sales	$	121,301		$	130,600		$	287,786		$	301,826
Natural gas sales		32,193			39,857			79,042			112,725
Total operating revenues		153,494			170,457			366,828			414,551
Operating costs and expenses:
Oil and natural gas production		25,439			27,041			76,022			65,915
Exploration and abandonments		2,776			16,824			10,195			20,288
Depreciation, depletion and amortization		54,835			32,528			157,985			75,822
Accretion of discount on asset retirement obligations		220			270			799			571
Impairments of long-lived assets		1,131			2,758			9,686			2,827
General and administrative (including non-cash stock-based compensation of $2,548 and $1,925 for the three months ended September 30, 2009 and 2008, respectively, and $6,661 and $4,954 for the nine months ended September 30, 2009 and 2008, respectively)		12,715			10,778			38,633			27,044
Bad debt expense		—			1,106			—			2,905
Ineffective portion of cash flow hedges		—			(416	)		—			(1,336	)
(Gain) loss on derivatives not designated as hedges		7,783			(163,312	)		94,435			(43,678	)
Total operating costs and expenses		104,899			(72,423	)		387,755			150,358
Income (loss) from operations		48,595			242,880			(20,927	)		264,193
Other income (expense):
Interest expense		(6,809	)		(10,255	)		(17,379	)		(19,755	)
Other, net		(200	)		334			(348	)		1,665
Total other expense		(7,009	)		(9,921	)		(17,727	)		(18,090	)
Income (loss) before income taxes		41,586			232,959			(38,654	)		246,103
Income tax (expense) benefit		(21,824	)		(91,031	)		11,973			(96,230	)
Net income (loss)	$	19,762		$	141,928		$	(26,681	)	$	149,873
Basic earnings per share:
Net income (loss) per share	$	0.23		$	1.75		$	(0.31	)	$	1.93
Weighted average shares used in basic earnings per share		85,061			81,288			84,798			77,489
Diluted earnings per share:
Net income (loss) per share	$	0.23		$	1.72		$	(0.31	)	$	1.90
Weighted average shares used in diluted earnings per share		86,088			82,724			84,798			78,945

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

2

Concho Resources Inc.

Consolidated Statement of Stockholders’ Equity
Unaudited

						Additional										Total
	Common Stock					Paid-in		Retained			Treasury Stock					Stockholders’
(in thousands)	Shares			Amount		Capital		Earnings			Shares		Amount			Equity
BALANCE AT DECEMBER 31, 2008		84,829		$	85	$	1,009,025	$	316,169			3	$	(125	)	$	1,325,154
Net loss		—			—		—		(26,681	)		—		—			(26,681	)
Stock options exercised		513			1		4,500		—			—		—			4,501
Stock-based compensation for restricted stock		269			—		3,433		—			—		—			3,433
Cancellation of restricted stock		(5	)		—		—		—			—		—			—
Stock-based compensation for stock options		—			—		3,228		—			—		—			3,228
Excess tax benefits related to stock-based compensation		—			—		3,357		—			—		—			3,357
Purchase of treasury stock		—			—		—		—			9		(292	)		(292	)
BALANCE AT SEPTEMBER 30, 2009		85,606		$	86	$	1,023,543	$	289,488			12	$	(417	)	$	1,312,700

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

3

Concho Resources Inc.

Consolidated Statements of Cash Flows
Unaudited

	Nine Months EndedSeptember 30,
(in thousands)	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(26,681	)	$	149,873
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		157,985			75,822
Impairments of long-lived assets		9,686			2,827
Accretion of discount on asset retirement obligations		799			571
Exploration expense, including dry holes		6,950			17,860
Non-cash compensation expense		6,661			4,954
Bad debt expense		—			2,905
Deferred income taxes		(21,840	)		86,908
(Gain) loss on sale of assets		147			(777	)
Ineffective portion of cash flow hedges		—			(1,336	)
(Gain) loss on derivatives not designated as hedges		94,435			(43,678	)
Dedesignated cash flow hedges reclassified from accumulated other comprehensive income		—			260
Other non-cash items		2,656			2,749
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		(10,367	)		26,209
Prepaid costs and other		(2,519	)		(1,035	)
Inventory		(3,979	)		(14,985	)
Accounts payable		5,029			(12,472	)
Revenue payable		17,581			6,982
Other current liabilities		(4,465	)		15,763
Net cash provided by operating activities		232,078			319,400
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and natural gas properties		(316,756	)		(213,666	)
Acquisition of oil and gas properties, businesses and other assets		—			(586,925	)
Additions to other property and equipment		(3,716	)		(6,711	)
Proceeds from the sale of oil and natural gas properties and other assets		1,004			1,034
Settlements received (paid) on derivatives not designated as hedges		77,590			(29,170	)
Net cash used in investing activities		(241,878	)		(835,438	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		672,650			767,800
Payments of long-term debt		(656,916	)		(460,700	)
Exercise of stock options		4,501			3,861
Excess tax benefit from stock-based compensation		3,357			2,884
Net proceeds from issuance of common stock		—			242,426
Proceeds from repayment of employee notes		—			333
Payments for loan costs		(8,933	)		(15,541	)
Purchase of treasury stock		(292	)		(125	)
Bank overdrafts		(6,624	)		(954	)
Net cash provided by financing activities		7,743			539,984
Net increase (decrease) in cash and cash equivalents		(2,057	)		23,946
Cash and cash equivalents at beginning of period		17,752			30,424
Cash and cash equivalents at end of period	$	15,695		$	54,370
SUPPLEMENTAL CASH FLOWS:
Cash paid for interest and fees, net of $33 and $1,090 capitalized interest	$	13,291		$	16,164
Cash paid for income taxes	$	5,598		$	5,964
NON-CASH INVESTING ACTIVITIES:
Deferred tax effect of acquired oil and gas properties	$	(835	)	$	200,786

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

4

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2009

Unaudited

Note A.Organization and nature of operations

     Concho Resources Inc. (the “Company”) is a Delaware corporation formed on February 22, 2006. The Company’s principal business is the acquisition, development, exploitation 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 material intercompany balances and transactions have been eliminated.

     Use of estimates in the preparation of financial statements.Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America 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 are 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 and oil and natural gas property acquisitions and fair value of stock-based compensation.

     Interim financial statements.The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2008 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, 2009, its results of operations for the three and nine months ended September 30, 2009 and 2008, and its cash flows for the nine months ended September 30, 2009 and 2008. 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, 2008.

     Deferred loan costs.Deferred loan costs are stated at cost, net of amortization, which is computed using the effective interest and straight-line methods. The Company had deferred loan costs of $22.0 million and $15.7 million, net of accumulated amortization of $7.5 million and $4.9 million, at September 30, 2009 and December 31, 2008, respectively.

5

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     Future amortization expense of deferred loan costs at September 30, 2009 is as follows:

					Total
	Credit		8.625%		Deferred
(in thousands)	Facility		Notes		Loan Costs
Remaining 2009	$	853	$	189	$	1,042
2010		3,411		802		4,213
2011		3,411		881		4,292
2012		3,411		968		4,379
2013 & thereafter		1,990		6,066		8,056
Total	$	13,076	$	8,906	$	21,982

     Intangible assets.The Company has capitalized certain operating rights acquired in an acquisition in 2008, see Note D. The gross operating rights of approximately $38.7 million, 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. Amortization expense for the three and nine months ended September 30, 2009 was approximately $0.4 million and $1.2 million, respectively, and $0.3 million for the three and nine months ended September 30, 2008. The following table reflects the estimated aggregate amortization expense at September 30, 2009 for each of the periods presented below:

(in thousands)
Remaining 2009	$	387
2010		1,549
2011		1,549
2012		1,549
2013		1,549
Thereafter		30,326
Total	$	36,909

     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.

6

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     The following table reflects the Company’s natural gas imbalance positions at September 30, 2009 and December 31, 2008 as well as amounts reflected in oil and natural gas production expense for the three and nine months ended September 30, 2009 and 2008:

	September 30, 2009						December 31, 2008
				Overtake						Overtake
				(Undertake)						(Undertake)
(dollars in thousands)	Amount			Volume (Mcf)			Amount			Volume (Mcf)
Natural gas imbalance receivable (included in other assets)	$	434			(96,549	)	$	406			(90,321	)
Natural gas imbalance liability (included in asset retirement obligations and other long-term liabilities)	$	(451	)		79,973		$	(472	)		85,698

	Three Months Ended September 30,						Nine Months Ended September 30,
(dollars in thousands)	2009			2008			2009			2008
Value of net overtake (undertake) arising during the period (increasing (reducing) oil and natural gas production expense)	$	(9	)	$	(45	)	$	(49	)	$	(182	)
Net overtake (undertake) position arising during the period (Mcf)		(1,882	)		(8,440	)		(11,951	)		(16,543	)

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

     General and administrative expense.The Company receives fees for the operation of jointly owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $3.2 million and $2.1 million for the three months ended September 30, 2009 and 2008, respectively, and $8.6 million and $2.6 million for the nine months ended September 30, 2009 and 2008, respectively.

     Reclassifications.Certain prior period amounts have been reclassified to conform to the 2009 presentation. These reclassifications had no impact on net income (loss), total stockholders’ equity or cash flows.

     Recent accounting pronouncements:

     In June 2009, the Financial Accounting Standards Board (“FASB”) issued ASC 105-10 (formerly Statement of Financial Accounting Standards No. 168),Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. The FASB Accounting Standards Codification (the “Codification”) has become the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in accordance with Generally Accepted Accounting Principles (“GAAP”). All existing accounting standard documents are superseded by the Codification and any accounting literature not included in the Codification will not be authoritative. However, rules and interpretive releases of the United States Securities and Exchange Commission (the “SEC”) issued under the authority of federal securities laws will continue to be the source of authoritative generally accepted accounting principles for SEC registrants. Effective September 30, 2009, there will be no more references made to the superseded FASB standards in the Company’s consolidated financial statements. The Codification does not change or alter existing GAAP and, therefore, will not have an impact on the Company’s financial position, results of operations or cash flows.

     ASU 2009-05.In August 2009, the FASB issued Accounting Standards Update (“ASU”) 2009-05,Fair Value Measurements and Disclosures (Topic 820)—Measuring Liabilities at Fair Value(“ASU 2009-05”). The FASB issued this update because some entities have expressed concern that there may be a lack of observable market information to measure the fair value of a liability. ASU 2009-05 is effective for the first reporting period beginning after August 28, 2009, with earlier application permitted. The guidance provides clarification on measuring liabilities at fair value when a quoted price in an active market is not available. In such circumstances, ASU 2009-05 specifies that a valuation technique should be applied that uses either the quote of the liability when traded as an asset, the quoted prices for similar liabilities or similar liabilities when traded as assets, or another valuation technique consistent with existing fair value measurement guidance. Examples of the alternative valuation methods include using a present value technique or a market

7

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

approach, which is based on the amount at the measurement date that the reporting entity would pay to transfer the identical liability or would receive to enter into the identical liability. The guidance also states that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustments to other inputs relating to the existence of a restriction that prevents the transfer of the liability. The Company adopted ASU 2009-05 effective September 30, 2009, and the adoption did not have a significant impact on the Company’s consolidated financial statements.

     ASU 2009-11.In September 2009, the FASB issued ASU 2009-11,Extractive Activities — Oil and Gas: Amendment to Section 932-10-S99, which makes a technical correction in ASC 932-10-S99-5 related to an SEC Observer comment, regarding the accounting and disclosures for gas balancing arrangements. The ASU amends FASB ASC 932-10-S99-5 because the SEC staff has not taken a position on whether the entitlements method or sales method is preferable for gas-balancing arrangements as defined in FASB ASC 932-815-55-1 and FASB ASC 932-815-55-2 that do not meet the definition of a derivative.

     With the entitlements method, sales revenue is recognized to the extent of each well partner’s proportionate share of gas sold regardless of which partner sold the gas. Under the sales method, sales revenue is recognized for all gas sold by a partner even if the partner’s ownership is less than 100% of the gas sold.

     ASU 2009-11 included an instruction in FASB ASC 932-10-S99-5 that public companies must account for all significant gas imbalances consistently using one accounting method. Both the method and any significant amount of imbalances in units and value should be disclosed in regulatory filings. The Company currently accounts for all gas balances under the sales method and makes all required disclosures.

     Recent developments in reserves reporting.In December 2008, the SEC released Final Rule,Modernization of Oil and Gas Reporting(the “Reserve Ruling”). The Reserve Ruling revises oil and natural gas reporting disclosures. The Reserve Ruling permits the use of new technologies to determine proved reserves estimates if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volume estimates. The Reserve Ruling will also allow, but not require, companies to disclose their probable and possible reserves to investors in documents filed with the SEC. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12-month period rather than a year-end price. The Reserve Ruling becomes effective for fiscal years ending on or after December 31, 2009. The Company is currently assessing the impact that adoption of the provisions of the Reserve Ruling will have on its financial position, results of operations and disclosures.

8

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

Note C.Exploratory well costs

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

     The following table reflects the Company’s capitalized exploratory well activity during the three and nine months ended September 30, 2009:

	Three Months Ended			Nine Months Ended
(in thousands)	September 30, 2009			September 30, 2009
Beginning capitalized exploratory well costs	$	7,304		$	25,553
Additions to exploratory well costs pending the determination of proved reserves		35,822			129,664
Reclassifications due to determination of proved reserves		(30,474	)		(142,114	)
Exploratory well costs charged to expense		—			(451	)
Ending capitalized exploratory well costs	$	12,652		$	12,652

     The following table provides an aging, at September 30, 2009 and December 31, 2008, of capitalized exploratory well costs based on the date drilling was completed:

	September 30,		December 31,
(in thousands)	2009		2008
Wells in drilling progress	$	2,958	$	7,765
Capitalized exploratory well costs that have been capitalized for a period of one year or less		9,694		17,788
Capitalized exploratory well costs that have been capitalized for a period greater than one year		—		—
Total capitalized exploratory well costs	$	12,652	$	25,553

     At September 30, 2009, the Company had eleven gross exploratory wells waiting on completion, seven of which were in the Company’s New Mexico Permian area, three of which were in the Company’s Texas Permian area and one was in the Company’s emerging play in North Dakota. At September 30, 2009, the Company had five gross exploratory wells drilling in the following areas: one in the New Mexico Permian area, one in the Texas Permian area, one in the emerging play in North Dakota and two in the Lower Abo oil play in New Mexico.

Note D.Acquisitions

     Henry Entities acquisition.On July 31, 2008, the Company closed the acquisition of Henry Petroleum LP and certain entities affiliated with Henry Petroleum LP (the “Henry Entities”) and additional non-operated interests in oil and natural gas properties from persons affiliated with the Henry Entities. In August 2008 and September 2008, the Company acquired additional non-operated interests in oil and natural gas properties from persons affiliated with the Henry Entities. The assets acquired in the Henry Entities acquisition, including the additional non-operated interests, are referred to as the “Henry Properties.” The Company paid $583.7 million in cash for the Henry Properties acquisition.

     The cash paid for the Henry Properties acquisition was funded with (i) borrowings under the Company’s credit facility and (ii) proceeds from a private placement of approximately 8.3 million shares of the Company’s common stock.

9

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     The Henry Properties acquisition was being accounted for using the purchase method of accounting for business combinations. Under the purchase method of accounting, the Company recorded the Henry Properties’ assets and liabilities at fair value. The purchase price of the acquired Henry Properties’ net assets is based on the total value of the cash consideration.

     The following tables represent the allocation of the total purchase price of the Henry Properties to the acquired assets and liabilities of the Henry Properties and the consideration paid for the Henry Properties. The allocation represents the fair values assigned to each of the assets acquired and liabilities assumed:

(in thousands)
Fair value of Henry Properties’ net assets:
Current assets, net of cash acquired of $19,049(a)	$	86,005
Proved oil and natural gas properties		593,634
Unproved oil and natural gas properties		233,527
Other long-term assets		7,392
Intangible assets — operating rights		38,717
Total assets acquired		959,275
Current liabilities		(114,394	)
Asset retirement obligations and other long-term liabilities		(7,529	)
Noncurrent derivative liabilities		(39,037	)
Deferred tax liability		(214,640	)
Total liabilities assumed		(375,600	)
Net purchase price	$	583,675
Consideration paid for Henry Properties’ net assets:
Cash consideration paid, net of cash acquired of $19,049	$	578,025
Acquisition costs(b)		5,650
Total purchase price	$	583,675

(a)	Includes a deferred tax asset of approximately $9.0 million.
(b)	Acquisition costs include legal and accounting fees, advisory fees and other acquisition-related costs.

10

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     The following unaudited pro forma combined condensed financial data for the three and nine months ended September 30, 2008 was derived from the historical financial statements of the Company and Henry Properties giving effect to the acquisition as if it had occurred on January 1, 2008. The unaudited pro forma combined condensed financial data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Henry Properties acquisition taken place as of the date indicated and is not intended to be a projection of future results.

	Nine Months Ended
(in thousands, except per share data)	September 30, 2008
Operating revenues	$	509,976
Net income	$	134,959
Earnings per common share:
Basic	$	1.57
Diluted	$	1.55

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 production lives, in accordance with applicable state laws. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.

     The following table summarizes the Company’s asset retirement obligations (“ARO”) recorded during the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2009			2008		2009			2008
Asset retirement obligations, beginning of period	$	14,386		$	10,356	$	16,809		$	9,418
Liabilities incurred from new wells		132			351		402			660
Liabilities incurred in acquisitions		—			7,062		—			7,062
Accretion expense		220			270		799			571
Disposition of wells sold		(81	)		—		(223	)		—
Liabilities settled upon plugging and abandoning wells		(630	)		—		(983	)		—
Revision of estimates		107			22		(2,670	)		350
Asset retirement obligations, end of period	$	14,134		$	18,061	$	14,134		$	18,061

Note F.Stockholders’ equity

     Common stock private placement.On June 5, 2008, the Company entered into a common stock purchase agreement with certain unaffiliated third-party investors to sell certain shares of the Company’s common stock in a private placement (the “Private Placement”) contemporaneous with the closing of the Henry Properties acquisition. On July 31, 2008, the Company issued 8,302,894 shares of its common stock at $30.11 per share. The Private Placement resulted in net proceeds of approximately $242.4 million to the Company, after payment of approximately $7.6 million for the fee paid to the placement agent.

11

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     Treasury stock.The restrictions on certain restricted stock awards issued to certain of the Company’s executive officers lapsed during the nine months ended September 30, 2009 and 2008. Immediately upon the lapse of restrictions, these executive officers became liable for certain federal 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 officers 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, 2009, the Company acquired 12,380 shares that are held as treasury stock in the approximate amount of $417,000.

Note G.Incentive plans

     Defined contribution plan.The Company sponsors a 401(k) defined contribution plan for the benefit of all employees and maintains certain other acquired plans. The Company matches 100 percent of employee contributions, not to exceed 6 percent of the employee’s salary. The Company’s contributions to the plans for the three months ended September 30, 2009 and 2008 were approximately $0.3 million and $0.2 million, respectively, and $0.8 million and $0.5 million for the nine months ended September 30, 2009 and 2008, respectively.

     Stock incentive plan.The Company’s 2006 Stock Incentive Plan (together with applicable 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 awards available under the Company’s Plan at September 30, 2009:

	Number of
	Common Shares
Approved and authorized awards		5,850,000
Restricted stock grants, net of forfeitures		(776,611	)
Stock option grants, net of forfeitures		(3,463,985	)
Awards available for future grant		1,609,404

     Restricted stock awards.All restricted shares are treated as issued and outstanding in the accompanying consolidated balance sheets. If an employee terminates employment prior to the date restrictions lapse, restricted shares awarded to such employee as to which restrictions have not lapsed are forfeited and cancelled and are no longer considered issued and outstanding. A summary of the Company’s restricted stock awards activity for the nine months ended September 30, 2009 is presented below:

	Number of			Grant Date
	Restricted			Fair Value
	Shares			Per Share
Outstanding at December 31, 2008		407,351
Shares granted		268,398		$	25.53
Shares cancelled / forfeited		(4,596	)
Lapse of restrictions		(193,358	)
Outstanding at September 30, 2009		477,795

12

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
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, 2009 and 2008:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2009		2008		2009		2008
Grant date fair value for awards during the period:
Employee grants	$	382	$	—	$	5,002	$	1,989
Officer and director grants(a)		84		577		1,934		1,419
Total	$	466	$	577	$	6,936	$	3,408
Stock-based compensation expense from restricted stock:
Employee grants	$	793	$	514	$	2,185	$	1,212
Officer and director grants(a)		440		202		1,248		366
Total	$	1,233	$	716	$	3,433	$	1,578
Income taxes and other information:
Income tax benefit related to restricted stock	$	137	$	276	$	1,064	$	617
Deductions in current taxable income related to restricted stock	$	699	$	68	$	5,066	$	1,268

(a) The three and nine months ended September 30, 2009 includes effects of modifications to certain stock-based awards, see further discussion below.

     Stock option awards.A summary of the Company’s stock option award activity under the Plan for the nine months ended September 30, 2009 is presented below:

				Weighted
				Average
	Number of			Exercise
	Options			Price
Outstanding at December 31, 2008		2,731,324		$	12.46
Options granted		120,301		$	20.75
Options exercised		(512,876	)	$	8.77
Outstanding at September 30, 2009		2,338,749		$	13.70
Vested at end of period		1,639,459		$	10.74
Vested and exercisable at end of period		814,467		$	13.34

13

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     The following table summarizes information about the Company’s vested and exercisable stock options outstanding at September 30, 2009:

					Weighted
					Average	Weighted
			Number of		Remaining	Average
			Stock		Contractual	Exercise		Intrinsic
			Options		Life	Price		Value
								(in thousands)
Vested options:
September 30, 2009:
Exercise price	$	8.00		1,121,212	2.38 years	$	8.00	$	31,753
Exercise price	$	12.00		118,681	4.63 years	$	12.00		2,886
Exercise price	$	14.84		263,750	6.96 years	$	14.84		5,664
Exercise price	$	21.84		102,250	8.42 years	$	21.84		1,481
Exercise price	$	31.81		33,566	8.76 years	$	31.81		152
				1,639,459		$	10.74	$	41,936
Vested and exercisable options:
September 30, 2009:
Exercise price	$	8.00		332,181	3.89 years	$	8.00	$	9,407
Exercise price	$	12.00		82,720	5.88 years	$	12.00		2,012
Exercise price	$	14.84		263,750	6.96 years	$	14.84		5,664
Exercise price	$	21.84		102,250	8.42 years	$	21.84		1,481
Exercise price	$	31.81		33,566	8.76 years	$	31.81		152
				814,467		$	13.34	$	18,716

14

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     The following table summarizes information about stock-based compensation for stock options for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2009		2008		2009		2008
Grant date fair value for awards during the period:
Employee grants	$	50	$	206	$	50	$	389
Officer and director grants(a)		2,907		585		4,361		5,675
Total	$	2,957	$	791	$	4,411	$	6,064
Stock-based compensation expense from stock options:
Employee grants	$	132	$	48	$	273	$	113
Performance vesting options- officers		22		149		93		433
Officer and director grants(a)		1,161		1,012		2,862		2,830
Total	$	1,315	$	1,209	$	3,228	$	3,376
Income taxes and other information:
Income tax benefit related to stock options	$	194	$	461	$	1,000	$	1,319
Deductions in current taxable income related to stock options exercised	$	1,729	$	2,880	$	8,886	$	8,218

(a) The three and nine months ended September 30, 2009 includes effects of modifications to certain stock-based awards, see further discussion below.

     In calculating compensation expense for stock options granted during the nine months ended September 30, 2009, the Company estimated the fair value of each grant using the Black-Scholes option-pricing model. Assumptions utilized in the model are shown below:

Risk-free interest rate	2.47	%
Expected term (years)	6.25
Expected volatility	63.19	%
Expected dividend yield	—

     The Company used the simplified method that is accepted by the SEC staff to calculate the expected term for stock options granted during the three and nine months ended September 30, 2009, since it does 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.

     Modification of stock-based awards.Steven L. Beal, the Company’s former President and Chief Operating Officer, retired from such positions on June 30, 2009. Mr. Beal began serving as a consultant on July 1, 2009; see Note M. 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 was still an employee of the Company while he is performing consulting services for the Company. As a result of this modification, the Company (i) immediately recognized $0.4 million of stock-based compensation during the three and nine months ended September 30, 2009 and (ii) will recognize additional stock-based compensation of $1.3 million in future periods.

15

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     Future stock-based compensation expense.Future stock-based compensation expense at September 30, 2009 is summarized in the table below:

	Restricted		Stock
(in thousands)	Stock		Options		Total
Remaining 2009	$	1,200	$	1,059	$	2,259
2010		3,612		2,279		5,891
2011		2,231		927		3,158
2012		682		199		881
2013		41		18		59
Total	$	7,766	$	4,482	$	12,248

Note H.Disclosures about fair value measurements

     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 our prices and valuation techniques, the Company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.

16

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
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, 2009, 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)			2009
Assets:
Commodity derivative price swap contracts	$	—	$	62,723		$	—		$	62,723
Commodity derivative price collar contracts		—		—			10,078			10,078
Interest rate derivative swap contracts		—		1,292			—			1,292
		—		64,015			10,078			74,093
Liabilities:
Commodity derivative price swap contracts		—		(58,186	)		—			(58,186	)
Commodity derivative basis swap contracts		—		(7,483	)		—			(7,483	)
Interest rate derivative swap contracts		—		(4,020	)		—			(4,020	)
Commodity derivative price collar contracts		—		—			(3,989	)		(3,989	)
		—		(69,689	)		(3,989	)		(73,678	)
Total financial assets (liabilities)	$	—	$	(5,674	)	$	6,089		$	415

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

(in thousands)
Balance at December 31, 2008	$	49,562
Realized and unrealized losses		(9,429	)
Purchases, issuances, and settlements		(34,044	)
Balance at September 30, 2009	$	6,089
Total losses for the period included in earnings attributable to the change in unrealized losses relating to assets still held at the reporting date	$	(43,473	)

17

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
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, 2009 and December 31, 2008:

	September 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
(in thousands)	value		value		value		value
Assets:
Derivative instruments	$	40,132	$	40,132	$	174,306	$	174,306
Liabilities:
Derivative instruments	$	39,717	$	39,717	$	1,866	$	1,866
Credit facility	$	350,000	$	324,342	$	630,000	$	553,645
8.625% senior notes due 2017	$	295,747	$	307,500	$	—	$	—

     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. The fair value at September 30, 2009 was approximately $324.3 million based on outstanding borrowings of $350 million and approximately $553.6 million at December 31, 2008 based on outstanding borrowings of $630 million.

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

     Derivative instruments.The fair value of the Company’s derivative instruments are estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table (i) summarizes the valuation of each of the Company’s financial instruments by required pricing levels and (ii) summarizes the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at September 30, 2009 and December 31, 2008:

18

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

	Fair value measurements using
	Quoted		Significant						Total
	prices		other			Significant			carrying value
	in active		observable			unobservable			at
	markets		inputs			inputs			September 30,
(in thousands)	(Level 1)		(Level 2)			(Level 3)			2009
Assets(1)
Current:(a)
Commodity derivative price swap contracts	$	—	$	19,580		$	—		$	19,580
Commodity derivative price collar contracts		—		—			10,078			10,078
		—		19,580			10,078			29,658
Noncurrent:(b)
Commodity derivative price swap contracts		—		43,143			—			43,143
Interest rate derivative swap contracts		—		1,292			—			1,292
		—		44,435			—			44,435
Liabilities(1)
Current:(a)
Commodity derivative price swap contracts		—		(32,432	)		—			(32,432	)
Commodity derivative basis swap contracts		—		(4,630	)		—			(4,630	)
Interest rate derivative swap contracts		—		(4,020	)		—			(4,020	)
Commodity derivative price collar contracts		—		—			(2,329	)		(2,329	)
		—		(41,082	)		(2,329	)		(43,411	)
Noncurrent:(b)
Commodity derivative price swap contracts		—		(25,754	)		—			(25,754	)
Commodity derivative basis swap contracts		—		(2,853	)		—			(2,853	)
Commodity derivative price collar contracts		—		—			(1,660	)		(1,660	)
		—		(28,607	)		(1,660	)		(30,267	)
Total financial assets (liabilities)	$	—	$	(5,674	)	$	6,089		$	415
(a)   Total current financial assets (liabilities), gross basis									$	(13,753	)
(b)   Total noncurrent financial assets (liabilities), gross basis										14,168
Total financial assets (liabilities)									$	415

19

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

	Fair value measurements using
	Quoted		Significant					Total
	prices		other			Significant		carrying value
	in active		observable			unobservable		at
	markets		inputs			inputs		December 31,
(in thousands)	(Level 1)		(Level 2)			(Level 3)		2008
Assets(1)
Current:(a)
Commodity derivative price swap contracts	$	—	$	64,162		$	—	$	64,162
Commodity derivative price collar contracts		—		—			49,562		49,562
		—		64,162			49,562		113,724
Noncurrent:(b)
Commodity derivative price swap contracts		—		60,995			—		60,995
Interest rate derivative swap contracts		—		678			—		678
		—		61,673			—		61,673
Liabilities(1)
Current:(a)
Commodity derivative price swap contracts		—		—			—		—
Commodity derivative basis swap contracts		—		(680	)		—		(680	)
Interest rate derivative swap contracts		—		(1,761	)		—		(1,761	)
		—		(2,441	)		—		(2,441	)
Noncurrent:(b)
Commodity derivative price swap contracts		—		(516	)		—		(516	)
		—		(516	)		—		(516	)
Total financial assets (liabilities)	$	—	$	122,878		$	49,562	$	172,440
(a)   Total current financial assets (liabilities), gross basis								$	111,283
(b)   Total noncurrent financial assets (liabilities), gross basis									61,157
Total financial assets (liabilities)								$	172,440

20

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

(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, 2009 and December 31, 2008:

	September 30,			December 31,
	2009			2008
Consolidated Balance Sheet Classification:
Current derivative contracts:
Assets	$	9,405		$	113,149
Liabilities		(23,158	)		(1,866	)
Net current	$	(13,753	)	$	111,283
Noncurrent derivative contracts:
Assets	$	30,727		$	61,157
Liabilities		(16,559	)		—
Net noncurrent	$	14,168		$	61,157

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 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 future cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and 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 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 gas properties that are sensitive to oil and natural gas prices for impairment. Due to downward adjustments to the economically recoverable resource potential associated with declines in commodity prices and well performance, the Company recognized impairment expense of $1.1 million and $9.7 million for the three and nine months ended September 30, 2009, respectively, related to its proved oil and gas properties. For the three months ended September 30, 2009, the impaired assets, which had a total carrying amount of $1.7 million, were reduced to their estimated fair value of $0.6 million. For the nine months ended September 30, 2009, the impaired assets, which had a total carrying amount of $15.9 million, were reduced to their estimated fair value of $6.2 million.

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

21

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

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

	Fair value measurements using
	Quoted		Significant
	prices		other		Significant
	in active		observable		unobservable		Total
	markets		inputs		inputs		Impairment
(in thousands)	(Level 1)		(Level 2)		(Level 3)		Loss
Three months ended September 30, 2009:
Impairment of long-lived assets	$	—	$	—	$	629	$	(1,131	)
Asset retirement obligations incurred in current period		—		—		132
Three months ended September 30, 2008:
Impairment of long-lived assets	$	—	$	—	$	2,068	$	(2,758	)
Asset retirement obligations incurred in current period		—		—		7,413
Nine months ended September 30, 2009:
Impairment of long-lived assets	$	—	$	—	$	6,249	$	(9,686	)
Asset retirement obligations incurred in current period		—		—		402
Nine months ended September 30, 2008:
Impairment of long-lived assets	$	—	$	—	$	2,075	$	(2,827	)
Asset retirement obligations incurred in current period		—		—		7,722

22

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

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 natural gas and oil 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. All of the Company’s remaining hedges that historically qualified for hedge accounting or were dedesignated from hedge accounting were settled in 2008.

23

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     New commodity derivatives contracts in 2009.During the nine months ended September 30, 2009, the Company entered into additional commodity derivative contracts to hedge a portion of its estimated future production. The following table summarizes information about these additional commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Aggregate		Index			Contract
	Volume		Price			Period
Oil (volumes in Bbls):
Price collar		600,000	$	45.00 - $49.00	(a)		3/1/09 - 5/31/09
Price swap		960,000	$	59.44	(a)		7/1/09 - 12/31/09
Price swap		273,000	$	67.50	(a)		8/1/09 - 12/31/09
Price swap		3,307,000	$	63.44	(a)		1/1/10 - 12/31/10
Price swap		2,601,000	$	71.66	(a)		1/1/11 - 12/31/11
Natural gas (volumes in MMBtus):
Price collar		1,500,000	$	5.00 - $5.81	(b)		10/1/09 - 12/31/09
Price collar		1,500,000	$	5.00 - $5.81	(b)		1/1/10 - 3/31/10
Price collar		3,000,000	$	5.25 - $5.75	(b)		4/1/10 - 9/30/10
Price collar		1,500,000	$	6.00 - $6.80	(b)		10/1/10 - 12/31/10
Price collar		1,500,000	$	6.00 - $6.80	(b)		1/1/11 - 3/31/11
Price swap		3,000,000	$	4.31	(b)		4/1/09 - 9/30/09
Price swap		1,050,000	$	4.66	(b)		7/1/09 - 12/31/09
Price swap		6,810,000	$	6.13	(b)		1/1/10 - 12/31/10
Price swap		300,000	$	7.29	(b)		1/1/11 - 3/31/11
Price swap		5,400,000	$	6.96	(b)		4/1/11 - 12/31/11
Basis swap		600,000	$	0.79	(c)		7/1/09 - 9/30/09
Basis swap		450,000	$	0.89	(c)		10/1/09 - 12/31/09
Basis swap		8,400,000	$	0.85	(c)		1/1/10 - 12/31/10
Basis swap		1,800,000	$	0.87	(c)		1/1/11 - 3/31/11
Basis swap		5,400,000	$	0.76	(c)		4/1/11 - 12/31/11

(a)	The index prices for the oil price swaps and collars 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.

24

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     In October 2009, the Company entered into the following oil and natural gas price swaps to hedge an additional portion of its estimated future production:

	Aggregate		Index			Contract
	Volume		Price			Period
Oil (volumes in Bbls):
Price swap		540,000	$	80.33	(a)		1/1/10 - 12/31/10
Natural gas (volumes in MMBtus):
Price swap		1,504,000	$	6.11	(b)		1/1/10 - 12/31/10

(a)	The index price for the oil price swap is 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.

25

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     Commodity derivative contracts at September 30, 2009.The following table sets forth the Company’s outstanding commodity derivative contracts at September 30, 2009. When aggregating multiple contracts, the weighted average contract price is disclosed.

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps:(a)
2009:
Volume (Bbl)								1,028,473		1,028,473
Price per Bbl							$	72.31	$	72.31
2010:
Volume (Bbl)		1,099,436		1,013,436		944,436		891,436		3,948,744
Price per Bbl	$	68.21	$	68.27	$	68.32	$	68.37	$	68.29
2011:
Volume (Bbl)		844,436		805,436		770,436		738,436		3,158,744
Price per Bbl	$	77.24	$	77.44	$	77.65	$	77.85	$	77.53
2012:
Volume (Bbl)		126,000		126,000		126,000		126,000		504,000
Price per Bbl	$	127.80	$	127.80	$	127.80	$	127.80	$	127.80
Oil Collars:(a)
2009:
Volume (Bbl)								192,000		192,000
Price per Bbl							$	120.00 - $134.60	$	120.00 - $134.60
Natural Gas Swaps:(b)
2009:
Volume (MMBtu)								460,000		460,000
Price per MMBtu							$	8.44	$	8.44
Natural Gas Swaps:(c)
2009:
Volume (MMBtu)								450,000		450,000
Price per MMBtu							$	4.66	$	4.66
2010:
Volume (MMBtu)		1,950,000		1,770,000		1,620,000		1,470,000		6,810,000
Price per MMBtu	$	6.11	$	6.12	$	6.13	$	6.15	$	6.13
2011:
Volume (MMBtu)		300,000		1,800,000		1,800,000		1,800,000		5,700,000
Price per MMBtu	$	7.29	$	6.96	$	6.96	$	6.96	$	6.98
Natural Gas Collars:(c)
2009:
Volume (MMBtu)								1,500,000		1,500,000
Price per MMBtu							$	5.00 - $5.81	$	5.00 - $5.81
2010:
Volume (MMBtu)		1,500,000		1,500,000		1,500,000		1,500,000		6,000,000
Price per MMBtu	$	5.00 - $5.81	$	5.25 - $5.75	$	5.25 - $5.75	$	6.00 - $6.80	$	5.38 - $6.03
2011:
Volume (MMBtu)		1,500,000		—		—		—		1,500,000
Price per MMBtu	$	6.00 - $6.80		—		—		—	$	6.00 - $6.80

26

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
Natural Gas Basis Swaps:(d)
2009:
Volume (MMBtu)								1,968,000		1,968,000
Price per MMBtu							$	1.03	$	1.03
2010:
Volume (MMBtu)		2,100,000		2,100,000		2,100,000		2,100,000		8,400,000
Price per MMBtu	$	0.85	$	0.85	$	0.85	$	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 and collars are based on the NYMEX-West Texas Intermediate monthly average futures price.
(b)	The index price for the natural gas price swap is based on the Inside FERC-El Paso Permian Basin first-of-the-month spot price.
(c)	The index prices for the natural gas price swaps and collars are based on the NYMEX-Henry Hub last trading day futures price.
(d)	The basis differential between the El Paso Permian delivery point and NYMEX Henry Hub delivery point.

     Interest rate derivative contracts at September 30, 2009.The Company entered into an interest rate swap which fixes the LIBOR interest rate on $300 million of the Company’s debt under its Credit Facility at 1.90 percent for three years, which commenced in May of 2009. For this portion of the Company’s debt under its Credit Facility, 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 debt outstanding under its Credit Facility.

27

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     The Company’s reported oil and natural gas revenue and average oil and natural gas prices includes the effects of oil quality and Btu content, gathering and transportation costs, natural gas processing and shrinkage, and the net effect of the commodity hedges that qualified for cash flow hedge accounting. The following table summarizes the gains and losses reported in earnings related to the commodity and interest rate derivative instruments and the net change in accumulated other comprehensive income (“AOCI”) for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2009			2008			2009			2008
Decrease in oil and natural gas revenue from derivative activity:
Cash payments on cash flow hedges in oil sales	$	—		$	(12,111	)	$	—		$	(32,684	)
Dedesignated cash flow hedges reclassified from AOCI in natural gas sales		—			(38	)		—			(260	)
Total decrease in oil and natural gas revenue from derivative activity	$	—		$	(12,149	)	$	—		$	(32,944	)
Gain (loss) on derivatives not designated as hedges:
Mark-to-market gain (loss):
Commodity derivatives:
Oil	$	(12,821	)	$	160,148		$	(156,920	)	$	71,248
Natural gas		(8,442	)		15,947			(13,460	)		1,600
Interest rate derivatives		(2,645	)		—			(1,645	)		—
Cash (payments) receipts on derivatives not designated as hedges:
Commodity derivatives:
Oil		13,971			(11,837	)		70,383			(27,802	)
Natural gas		3,395			(946	)		9,227			(1,368	)
Interest rate derivatives		(1,241	)		—			(2,020	)		—
Total gain (loss) on derivatives not designated as hedges	$	(7,783	)	$	163,312		$	(94,435	)	$	43,678
Gain from ineffective portion of cash flow hedges	$	—		$	416		$	—		$	1,336
Accumulated other comprehensive income (loss):
Cash flow hedges:
Mark-to-market gain (loss) of cash flow hedges	$	—		$	14,588		$	—		$	(17,922	)
Reclassification adjustment of losses to earnings		—			12,111			—			32,684
Net change, before income taxes		—			26,699			—			14,762
Income tax effect		—			(10,441	)		—			(5,776	)
Net change, net of income taxes	$	—		$	16,258		$	—		$	8,986
Dedesignated cash flow hedges:
Reclassification adjustment of losses to earnings	$	—		$	38		$	—		$	260
Income tax effect		—			(15	)		—			(102	)
Net change, net of income taxes	$	—		$	23		$	—		$	158

28

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

Note J.Debt

     The Company’s debt consisted of the following:

	September 30,			December 31,
(in thousands)	2009			2008
Credit facility	$	350,000		$	630,000
8.625% unsecured senior notes due 2017		300,000			—
Less: unamortized original issue discount		(4,253	)		—
Less: current portion		—			—
Total long-term debt	$	645,747		$	630,000

     Credit facility.The Company’s credit facility, as amended, has a maturity date of July 31, 2013 (the “Credit Facility”). At September 30, 2009, the Company had letters of credit outstanding under the Credit Facility of approximately $25,000 and its availability to borrow additional funds was approximately $605.9 million. The Company obtained a waiver from lenders representing 95.4% of the commitments under the Credit Facility in conjunction with the offering of the Senior Notes, described below, to not reduce the borrowing base as required by the Credit Facility; as a result, the Company’s borrowing base was reduced to $955.9 million from $960 million. In October 2009, the lenders reaffirmed the Company’s $955.9 million borrowing base under the Credit Facility until the next scheduled borrowing base redetermination in April 2010. Between scheduled borrowing base redeterminations, the Company and, if requested by 66 2/3 percent of the lenders, the lenders, may each request one special redetermination.

     Advances on the Credit Facility bear interest, at the Company’s option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) (3.25 percent at September 30, 2009) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). At September 30, 2009, the interest rates of Eurodollar rate advances and JPM Prime Rate advances vary, 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, 2009, the Company pays 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 this facility is the JPM Prime Rate plus the applicable interest margin.

     The Company’s obligations under the Credit Facility are secured by a first lien on substantially all of 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 agreement 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, 2009, 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”) at 98.578% of par. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries.

29

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     The Senior Notes will mature on October 1, 2017, and interest is payable on the Senior Notes each April 1 and October 1, commencing on April 1, 2010. 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. The Company may also redeem up to 35% 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.

     The Senior Notes are the Company’s senior unsecured obligations, and rank equally in right of payment with all of the Company’s existing and future senior debt, and rank senior in right of payment to all of the Company’s future subordinated debt. The Senior Notes are structurally subordinated to all of the Company’s existing and future secured debt to the extent of the value of the collateral securing such indebtedness.

     Principal maturities of debt.Principal maturities of debt outstanding, excluding original issue discount, at September 30, 2009 are as follows:

(in thousands)
Remaining 2009	$	—
2010		—
2011		—
2012		—
2013		350,000
Thereafter		300,000
Total	$	650,000

     Interest expense.The following amounts have been incurred and charged to interest expense for the three and nine months ended September 30, 2009 and 2008:

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
(in thousands)	2009			2008			2009			2008
Cash payments for interest	$	6,395		$	6,496		$	13,324		$	17,254
Amortization of original issue discount		13			8			13			58
Amortization of deferred loan origination costs		883			674			2,596			1,300
Write-off of deferred loan origination costs and original issue discount		57			1,547			57			1,547
Net changes in accruals		(524	)		1,780			1,422			686
Interest costs incurred		6,824			10,505			17,412			20,845
Less: capitalized interest		(15	)		(250	)		(33	)		(1,090	)
Total interest expense	$	6,809		$	10,255		$	17,379		$	19,755

Note K.Commitments and contingencies

     Severance agreements.The Company has entered into severance and change of control agreements with all of its officers. The current annual salaries for the Company’s officers covered under such agreements total approximately $2.0 million.

30

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

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

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

     Acquisition commitments.In connection with the acquisition of the Henry Entities, the Company agreed to pay certain employees, who were formerly employed by the Henry Entities, bonuses of approximately $11.0 million in the aggregate at each of the first and second anniversaries of the closing of the acquisition, respectively. Except as described below, these employees must remain employed with the Company to receive the bonus. A former Henry Entities employee who is otherwise entitled to a full bonus will receive the full bonus (i) if the Company terminates the employee without cause, (ii) upon the death or disability of such employee or (iii) upon a change in control of the Company. If any such employee resigns or is terminated for cause, the employee will not receive the bonus and, subject to certain conditions, the Company will be required to reimburse the sellers in the acquisition of the Henry Entities 65 percent of the bonus amount not paid to the employee. The Company will reflect the bonus amounts to be paid to these employees as a period cost, which will be included in the Company’s results of operations over the period earned. Amounts that ultimately are determined to be paid to the sellers will be treated as a “contingent purchase price” and reflected as an adjustment to the purchase price. During the three and nine months ended September 30, 2009, the Company recognized $2.4 million and $7.7 million, respectively, of this obligation in its results of operations, and $0.2 million as contingent purchase price. During the three and nine months ended September 30, 2008, the Company recognized $2.4 million of the obligation in its results of operations and $0.7 million as contingent purchase price.

     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, 2009:

	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	$	—	$	—	$	—
Daywork drilling contracts assumed in the Henry Properties acquisition(b)		1,085		1,085		—		—		—
Total contractual drilling commitments	$	2,085	$	2,085	$	—	$	—	$	—

(a)	Consists of daywork drilling contracts with Silver Oak Drilling, LLC, an affiliate of Chase Oil Corporation.
(b)	A major oil and gas company which owns an interest in the wells being drilled and the Company are parties to these contracts. Only the Company’s 25% share of the contract obligation has been reflected above.

31

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
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, 2009 and 2008 were approximately $693,000 and $571,000, respectively, and $1,946,000 and $851,000 for the nine months ended September 30, 2009 and 2008, respectively. Future minimum lease commitments under non-cancellable operating leases at September 30, 2009 are as follows:

(in thousands)
Remaining 2009	$	268
2010		1,077
2011		1,083
2012		1,077
2013		1,084
Thereafter		3,261
Total	$	7,850

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. In determining the interim period income tax provision, the Company utilizes an estimated annual effective tax rate.

     At September 30, 2009, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2004 through 2008 remain subject to examination by the major tax jurisdictions.

32

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     Income tax provision.The Company’s income tax provision and amounts separately allocated were attributable to the following items for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2009			2008			2009			2008
Income (loss) from operations	$	21,824		$	91,031		$	(11,973	)	$	96,230
Changes in stockholders’ equity:
Net deferred hedge gains (losses)		—			5,692			—			(7,013	)
Net settlement losses included in earnings		—			4,764			—			12,891
Tax benefits related to stock-based compensation		(365	)		(738	)		(3,357	)		(2,884	)
	$	21,459		$	100,749		$	(15,330	)	$	99,224

     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, 2009 and 2008:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2009		2008		2009			2008
Current:
U.S. federal	$	2,766	$	7,620	$	8,060		$	8,234
U.S. state and local		1,099		1,007		1,807			1,088
		3,865		8,627		9,867			9,322
Deferred:
U.S. federal		15,941		73,865		(19,162	)		77,902
U.S. state and local		2,018		8,539		(2,678	)		9,006
		17,959		82,404		(21,840	)		86,908
	$	21,824	$	91,031	$	(11,973	)	$	96,230

     The reconciliation between the tax expense computed by multiplying pretax income (loss) by the U.S. federal statutory rate and the reported amounts of income tax expense (benefit) is as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2009		2008			2009			2008
Income (loss) at U.S. federal statutory rate	$	14,555	$	81,536		$	(13,529	)	$	86,136
State income taxes (net of federal tax effect)		1,762		9,546			(830	)		10,094
Nondeductible expense & other		5,507		(51	)		2,386			—
Income tax expense (benefit)	$	21,824	$	91,031		$	(11,973	)	$	96,230

33

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

Note M.Related party transactions

     Consulting Agreement.On June 30, 2009, Steven L. Beal, the Company’s President and Chief Operating Officer, retired from such positions. Mr. Beal was recently re-elected to the Company’s Board of Directors and continues to serve as a member of the Company’s Board of Directors. 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 was still an employee of the Company while he is performing consulting services for the Company.

     Chase Group transactions.The Company incurred charges from Mack Energy Corporation (“MEC”), an affiliate of Chase Oil Corporation (“Chase Oil”), of approximately $0.3 million and $0.2 million for the three months ended September 30, 2009 and 2008, respectively, and $1.0 million and $1.7 million for the nine months ended September 30, 2009 and 2008, respectively, for services rendered in the ordinary course of business.

     The Company had $38,000 in outstanding receivables due from MEC at September 30, 2009 and no outstanding receivables due from MEC at December 31, 2008. The Company had $46,000 in outstanding payables to MEC at September 30, 2009 and no outstanding payables to MEC at December 31, 2008.

     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, 2009, the Company owned 95.4% of the system and Chase Oil and its affiliates owned 4.6%.

     Other related party transactions.The Company also has engaged in transactions with certain other affiliates of Chase Oil, Caza Energy LLC (“Caza”) and certain other parties thereto (collectively the “Chase Group”), including a drilling contractor, an oilfield services company, a supply company, a drilling fluids supply company, a pipe and tubing supplier, a fixed base operator of aircraft services and a software company.

     The Company incurred charges from these related party vendors of approximately $5.3 million and $6.5 million for the three months ended September 30, 2009 and 2008, respectively, and $17.9 million and $19.6 million for the nine months ended September 30, 2009 and 2008, respectively.

     The Company had outstanding amounts payable to these related party vendors identified above of approximately $0.4 million and $21,000 at September 30, 2009 and December 31, 2008, respectively, which are reflected in accounts payable—related parties in the accompanying consolidated balance sheets.

     Overriding royalty and royalty interests.Certain members of the Chase Group own overriding royalty interests in certain of the Chase Group properties. The amount paid attributable to such interests was approximately $402,000 and $984,000 for the three months ended September 30, 2009 and 2008, respectively, and $901,000 and $2.6 million for the nine months ended September 30, 2009 and 2008, respectively. The Company owed these owners royalty payments of approximately $253,000 and $146,000 at September 30, 2009 and December 31, 2008, respectively.

     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 owner of a 3.5% partnership interest. The Company paid this partnership approximately $39,000 and $115,000 for the three months ended September 30, 2009 and 2008, respectively, and $95,000 and $279,000 for the nine months

34

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

ended September 30, 2009 and 2008, respectively. The Company owed this partnership royalty payments of approximately $13,000 at September 30, 2009 and December 31, 2008.

     In April 2005, the Company acquired certain working interests in 46,861 gross (26,908 net) acres located in Culberson County, Texas from an entity partially owned by a person who became an executive officer of the Company immediately following such acquisition. In connection with this acquisition, such entity retained a 2% overriding royalty interest in the acquired properties, which overriding royalty interest later became owned equally by such officer and a non-officer employee of the Company. During the three and nine months ended September 30, 2009 and 2008, no payments were made related to this overriding royalty interest. Effective March 31, 2008, the executive officer involved in this matter resigned from the Company.

     Working interests owned by employees.As part of the Henry Properties acquisition, the Company purchased oil and natural gas properties in which certain employees owned interests. The Company distributed revenues to these employees totaling approximately $66,000 and $192,000 for the three and nine months ended September 30, 2009, respectively, and received joint interest payments from these employees of approximately $95,000 and $979,000 for the three and nine months ended September 30, 2009, respectively. The Company distributed revenues to these employees totaling approximately $34,000 for the three and nine months ended September 30, 2008, and received joint interest payments from these employees of approximately $635,000 for the three and nine months ended September 30, 2008.

     At September 30, 2009 and December 31, 2008, the Company was owed by these employees approximately $100,000 and $300,000, respectively, which is reflected in accounts receivable - related parties. The Company owed these employees revenue payments of approximately $13,000 at September 30, 2009 and had no outstanding payables at December 31, 2008.

Note N.Net income (loss) per share

     Basic net income (loss) per share is computed by dividing net income (loss) applicable to common shareholders by the weighted average number of common shares treated as outstanding for the period. All capital options were exercised prior to March 31, 2008.

     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 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:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2009		2008		2009		2008
Weighted average common shares outstanding:
Basic		85,061		81,288		84,798		77,489
Dilutive capital options		—		—		—		8
Dilutive common stock options		789		1,195		—		1,203
Dilutive restricted stock		238		241		—		245
Diluted		86,088		82,724		84,798		78,945

     Stock options equivalent to 65,891 and 96,555 shares of common stock were not included in the computation of diluted income per share for the three months ended September 30, 2009 and 2008, respectively, as inclusion of these items would be antidilutive.

35

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

     For the nine months ended September 30, 2009, the computation of diluted net loss per share was anti-dilutive due to the net loss reported by the Company; therefore, the amounts reported for basic and diluted net loss per share were the same. For the nine months ended September 30, 2009, 477,795 shares of restricted stock and 2,338,749 stock options were not included in the computation of diluted loss per share, as inclusion of these items would be anti-dilutive.

     For the nine months ended September 30, 2008, the effects of all potentially dilutive securities were included in the computation of diluted earnings per share because there were no antidilutive effects.

Note O.Other current liabilities

     The following table provides the components of the Company’s other current liabilities at September 30, 2009 and December 31, 2008:

	September 30,		December 31,
(in thousands)	2009		2008
Other current liabilities:
Accrued oil and natural gas related costs	$	24,585	$	15,489
Payroll related matters		8,364		11,290
Accrued interest		1,775		353
Income taxes payable		1,475		—
Asset retirement obligations		1,473		2,611
Other		4,532		8,314
Other current liabilities	$	42,204	$	38,057

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 Consolidating Condensed Financial Statements in order to quantify the assets and results of operations of such subsidiaries as subsidiary guarantors. The following Consolidating Condensed Balance Sheets at September 30, 2009 and December 31, 2008, and Consolidating Statements of Operations for the three and nine months ended September 30, 2009 and 2008 and Consolidating Condensed Statements of Cash Flows for the nine months ended September 30, 2009 and 2008, 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 taxes are recorded on Concho Resources Inc. as the subsidiaries are flow-through entities for tax purposes. The subsidiary guarantors are not restricted from making distributions to the Company.

36

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

Consolidating Condensed Balance Sheet
September 30, 2009
(in thousands)

	Parent		Subsidiary		Consolidating
	Issuer		Guarantors		Entries			Total
ASSETS
Accounts receivable — related parties	$	1,718,424	$	2,683	$	(1,720,969	)	$	138
Other current assets		20,010		158,775		—			178,785
Total oil and natural gas properties, net		—		2,512,021		—			2,512,021
Total property and equipment, net		—		16,151		—			16,151
Investment in subsidiaries		800,070		—		(800,070	)		—
Total other long-term assets		52,708		61,723		—			114,431
Total assets	$	2,591,212	$	2,751,353	$	(2,521,039	)	$	2,821,526
LIABILITIES AND EQUITY
Accounts payable — related parties	$	—	$	1,721,762	$	(1,720,969	)	$	793
Other current liabilities		27,245		214,195		—			241,440
Other long-term liabilities		605,520		15,326		—			620,846
Long-term debt		645,747		—		—			645,747
Equity		1,312,700		800,070		(800,070	)		1,312,700
Total liabilities and equity	$	2,591,212	$	2,751,353	$	(2,521,039	)	$	2,821,526

Consolidating Condensed Balance Sheet
December 31, 2008
(in thousands)

	Parent		Subsidiary		Consolidating
	Issuer		Guarantors		Entries			Total
ASSETS
Accounts receivable — related parties	$	2,500,186	$	1,432,829	$	(3,932,701	)	$	314
Other current assets		120,406		158,063		—			278,469
Total oil and natural gas properties, net		—		2,386,584		—			2,386,584
Total property and equipment, net		—		14,820		—			14,820
Investment in subsidiaries		734,969		—		(734,969	)		—
Total other long-term assets		73,538		61,478		—			135,016
Total assets	$	3,429,099	$	4,053,774	$	(4,667,670	)	$	2,815,203
LIABILITIES AND EQUITY
Accounts payable — related parties	$	860,758	$	3,072,255	$	(3,932,701	)	$	312
Other current liabilities		39,424		231,082		—			270,506
Other long-term liabilities		573,763		15,468		—			589,231
Long-term debt		630,000		—		—			630,000
Equity		1,325,154		734,969		(734,969	)		1,325,154
Total liabilities and equity	$	3,429,099	$	4,053,774	$	(4,667,670	)	$	2,815,203

37

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

Consolidating Condensed Statement of Operations
For the Three Months Ended September 30, 2009
(in thousands)

	Parent			Subsidiary			Consolidating
	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

Consolidating Condensed Statement of Operations
For the Three Months Ended September 30, 2008
(in thousands)

	Parent			Subsidiary		Consolidating
	Issuer			Guarantors		Entries			Total
Total operating revenues	$	(12,150	)	$	182,607	$	—		$	170,457
Total operating costs and expenses		19,782			52,641		—			72,423
Income (loss) from operations		7,632			235,248		—			242,880
Interest expense		(10,255	)		—		—			(10,255	)
Other, net		235,582			329		(235,577	)		334
Income before income taxes		232,959			235,577		(235,577	)		232,959
Income tax expense		(91,031	)		—		—			(91,031	)
Net income	$	141,928		$	235,577	$	(235,577	)	$	141,928

38

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

Consolidating Condensed Statement of Operations
For the Nine Months Ended September 30, 2009
(in thousands)

	Parent			Subsidiary			Consolidating
	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	)

Consolidating Condensed Statement of Operations
For the Nine Months Ended September 30, 2008
(in thousands)

	Parent			Subsidiary			Consolidating
	Issuer			Guarantors			Entries			Total
Total operating revenues	$	(32,945	)	$	447,496		$	—		$	414,551
Total operating costs and expenses		19,638			(169,996	)		—			(150,358	)
Income (loss) from operations		(13,307	)		277,500			—			264,193
Interest expense		(19,755	)		—			—			(19,755	)
Other, net		279,165			1,660			(279,160	)		1,665
Income before income taxes		246,103			279,160			(279,160	)		246,103
Income tax expense		(96,230	)		—			—			(96,230	)
Net income	$	149,873		$	279,160		$	(279,160	)	$	149,873

39

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

Consolidating Condensed Statement of Cash Flows
For the Nine Months Ended September 30, 2009
(in thousands)

	Parent			Subsidiary			Consolidating
	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 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

Consolidating Condensed Statement of Cash Flows
For the Nine Months Ended September 30, 2008
(in thousands)

	Parent			Subsidiary			Consolidating
	Issuer			Guarantors			Entries		Total
Net cash flows provided by (used in) operating activities	$	(514,355	)	$	833,755		$	—	$	319,400
Net cash flows used in investing activities		(26,175	)		(809,263	)		—		(835,438	)
Net cash flows provided by (used in) financing activities		540,938			(954	)		—		539,984
Net increase in cash and cash equivalents		408			23,538			—		23,946
Cash and cash equivalents at beginning of period		107			30,317			—		30,424
Cash and cash equivalents at end of period	$	515		$	53,855		$	—	$	54,370

Note Q.Subsequent events

     The Company has evaluated subsequent events through November 5, 2009, which was the date these financial statements were issued.

40

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2009
Unaudited

Note R.Supplementary information

Capitalized costs

	September 30,			December 31,
(in thousands)	2009			2008
Oil and natural gas properties:
Proved	$	2,706,933		$	2,316,330
Unproved		273,335			377,244
Less: accumulated depletion		(468,247	)		(306,990	)
Net capitalized costs for oil and natural gas properties	$	2,512,021		$	2,386,584

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

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2009			2008		2009			2008
Property acquisition costs:(b)
Proved	$	(467	)	$	589,986	$	(1,475	)	$	589,987
Unproved		7,618			223,892		12,200			225,241
Exploration		26,065			30,131		111,005			80,638
Development		64,554			78,477		179,783			149,913
Total costs incurred for oil and natural gas properties	$	97,770		$	922,486	$	301,513		$	1,045,779

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

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2009			2008		2009			2008
Proved property acquisition costs	$	—		$	7,062	$	—		$	7,062
Exploration costs		(70	)		115		150			309
Development costs		(321	)		258		(3,048	)		701
Total	$	(391	)	$	7,435	$	(2,898	)	$	8,072

(b) During the three and nine months ended September 30, 2009, the Company adjusted the purchase price allocation related to the acquisition of the Henry Properties. This adjustment reduced the proved acquisition costs by $350,000 and $1,371,000 during the three and nine months ended September 30, 2009, respectively, while the unproved acquisition costs were increased by $35,000 and $328,000 during the three and nine months ended September 30, 2009, respectively.

41

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 included in our Annual Report on Form 10-K for the year ended December 31, 2008.

     During the third quarter of 2008, we closed a significant acquisition as discussed below. As a result of the acquisition many comparisons between periods will be difficult or impossible.

     Statements in this discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenue and expenses to differ materially from our expectations. See “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

     We are an independent oil and natural gas company engaged in the acquisition, development, exploitation and exploration of producing oil and natural gas properties. Our 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 drilling or participating in drilling in emerging plays located in the Permian Basin of Southeast New Mexico and the Williston Basin in North Dakota, where we are applying horizontal drilling and advanced fracture stimulation techniques. Oil comprised 62.9 percent of our 137.3 MMBoe of estimated net proved reserves at December 31, 2008, and 66.9 percent of our 8.1 MMBoe of production during the nine months ended September 30, 2009. We generally seek to operate the wells in which we own an interest, and we operated wells that accounted for 93.1 percent of our proved developed producing PV-10 at December 31, 2008 and 65.6 percent of our 3,831 gross wells at September 30, 2009. By controlling operations, we believe that we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling, completion and stimulation methods used.

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 the decline of 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 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, 2009.

42

     Oil prices in 2008 were high and particularly volatile compared to historical prices. In addition, natural gas prices have been subject to significant fluctuations during the past several years. In general, oil and natural gas prices were substantially lower during the comparable periods of 2009 measured against 2008. The following table sets forth the average NYMEX oil and natural gas prices for the three and nine months ended September 30, 2009 and 2008, as well as the high and low NYMEX price for the same periods:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Average NYMEX prices:
Oil (Bbl)	$	68.24	$	118.67	$	57.22	$	113.59
Natural gas (MMBtu)	$	3.42	$	9.02	$	3.90	$	9.74
High / Low NYMEX prices:
Oil (Bbl):
High	$	74.37	$	145.29	$	74.37	$	145.29
Low	$	59.52	$	91.15	$	33.98	$	86.99
Natural gas (MMBtu):
High	$	4.88	$	13.58	$	6.07	$	13.58
Low	$	2.51	$	7.22	$	2.51	$	7.22

     Further demonstrating the continuing volatility, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $81.37 and $69.57 per Bbl and $5.16 and $4.29 per MMBtu, respectively, during the period from October 1, 2009 to November 2, 2009. At November 2, 2009, the NYMEX oil price and NYMEX natural gas price were $78.13 per Bbl and $4.82 per MMBtu, respectively.

2010 capital budget

     On November 5, 2009, our board of directors approved a capital budget for 2010 of approximately $506 million. The capital budget is predicated on us funding it substantially within our cash flow. If commodity prices decline, below those at the time of the capital budget approval, and considering other factors that may change, we expect we would adjust our spending such that we spend substantially within our cash flow. The following is a summary of our 2010 capital budget:

(in millions)	2010 Budget
Drilling and recompletion opportunities in our core operating area	$	383
Projects operated by third parties		8
Emerging plays, acquisition of leasehold acreage and other property interests, and geological and geophysical		82
Maintenance capital in our core operating areas		33
Total 2010 capital budget	$	506

Senior Notes Issuance

     On September 18, 2009, we issued $300 million in principal amount of 8.625% senior notes due 2017 at 98.578% of par. The 8.625% senior notes will mature on October 1, 2017 and interest is paid in arrears semi-annually on April 1 and October 1 beginning April 1, 2010. We used the net proceeds of $288.2 million (net of related estimated offering costs) to repay a portion of the borrowings under our credit facility. The senior notes are senior unsecured obligations of ours and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness.

     We issued the senior notes to (i) extend the maturities of our debt to better match the long-lived nature of our assets, (ii) increase liquidity under our credit facility and (iii) reduce our dependency on bank debt.

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Borrowing base

     Pursuant to the terms of our credit facility, our borrowing base was to be reduced by $0.30 for every dollar of new indebtedness evidenced by unsecured senior notes or unsecured senior subordinated notes that we issue. As a result of this provision, the borrowing base under our credit facility would have been reduced by $90 million due to our issuance and sale of the senior notes. However, we received waivers of this provision from lenders representing approximately 95.4% of our borrowing base, resulting in an actual reduction of approximately $4.1 million in our borrowing base, which reduced our borrowing base to $955.9 million.

     On October 23, 2009, our borrowing base of $955.9 million was reaffirmed by our lenders under our credit facility. At September 30, 2009, we have $605.9 million of availability under our credit facility based on the reaffirmed borrowing base.

2009 capital budget

     On November 6, 2008, our board of directors approved the following capital budget for 2009, predicated on us funding it substantially within our cash flow:

			Current 2009
	Original 2009		Planned Capital
(in millions)	Budget		Expenditures
Drilling and recompletion opportunities in our core operating area	$	398	$	316
Projects operated by third parties		8		5
Emerging plays, acquisition of leasehold acreage and other property interests, and geological and geophysical		72		60
Maintenance capital in our core operating areas		22		19
Total 2009 capital budget	$	500	$	400

     In January 2009, in light of the significant drop in commodity prices during the fourth quarter of 2008, we took actions to reduce our activities to a level that would allow us to fund our capital expenditures substantially within our cash flow, which at the time resulted in estimated annual capital expenditures of approximately $300 million for 2009. As a result of improved commodity prices, in particular oil prices, we recently increased our estimated capital expenditures for 2009 to approximately $400 million, which we believe we can substantially fund within our cash flow. We will continue to monitor our capital expenditures, at least on a quarterly basis, in relation to our cash flow and expect to adjust our activity and capital spending level based on changes in commodity prices and the cost of goods and services and other considerations. For clarity purposes we view “our” cash flow as our cash flow from operations before changes in working capital, and we include the cash payments/receipts on our derivatives that are included in our investing activities.

     During the first nine months of 2009, we incurred approximately $305.5 million of capital expenditures (excluding the effects of asset retirement obligations and adjustments to the acquisition of the Henry Properties). These costs were in line with our cash flows (as described in the previous paragraph) during the period. For the balance of 2009, we expect to use the remaining approximately $94.5 million of our planned capital expenditures to pursue increased opportunities in our core operating areas along with targeted opportunities in our emerging plays.

Henry Entities acquisition

     On July 31, 2008, we closed the acquisition of Henry Petroleum LP and certain entities affiliated with Henry Petroleum LP (the “Henry Entities”) and additional non-operated interests in oil and natural gas properties from persons affiliated with the Henry Entities. In August 2008 and September 2008, we acquired additional non-operated interests in oil and natural gas properties from persons affiliated with the Henry Entities. The assets acquired in the Henry Entities acquisition, including the additional non-operated interests, are referred to as the “Henry Properties.” We paid $583.7 million in cash for the Henry Properties acquisition, which was funded with borrowings under our credit facility, which was amended and restated on July 31, 2008, and net proceeds of approximately $242.4 million from our private placement of 8,302,894 shares of our common stock.

Derivative financial instrument exposure

     At September 30, 2009, the fair value of our financial derivatives was a net asset of $0.4 million. All of our counterparties to these financial derivatives are parties to our credit facility and have their outstanding debt commitments and derivative exposures collateralized pursuant to our credit facility. Pursuant to 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.

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     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 under our credit facility against amounts we may be owed related to our derivative financial instruments with such party.

     New commodity derivative contracts.During the nine months ended September 30, 2009, we entered into additional commodity derivative contracts to economically hedge a portion of our estimated future production. The following table summarizes information about these additional commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Aggregate		Index			Contract
	Volume		Price			Period
Oil (volumes in Bbls):
Price collar		600,000	$	45.00 - $49.00	(a)	3/1/09 - 5/31/09
Price swap		960,000	$	59.44	(a)	7/1/09 - 12/31/09
Price swap		273,000	$	67.50	(a)	8/1/09 - 12/31/09
Price swap		3,307,000	$	63.44	(a)	1/1/10 - 12/31/10
Price swap		2,601,000	$	71.66	(a)	1/1/11 - 12/31/11
Natural gas (volumes in MMBtus):
Price collar		1,500,000	$	5.00 - $5.81	(b)	10/1/09 - 12/31/09
Price collar		1,500,000	$	5.00 - $5.81	(b)	1/1/10 - 3/31/10
Price collar		3,000,000	$	5.25 - $5.75	(b)	4/1/10 - 9/30/10
Price collar		1,500,000	$	6.00 - $6.80	(b)	10/1/10 - 12/31/10
Price collar		1,500,000	$	6.00 - $6.80	(b)	1/1/11 - 3/31/11
Price swap		3,000,000	$	4.31	(b)	4/1/09 - 9/30/09
Price swap		1,050,000	$	4.66	(b)	7/1/09 - 12/31/09
Price swap		6,810,000	$	6.13	(b)	1/1/10 - 12/31/10
Price swap		300,000	$	7.29	(b)	1/1/11 - 3/31/11
Price swap		5,400,000	$	6.96	(b)	4/1/11 - 12/31/11
Basis swap		600,000	$	0.79	(c)	7/1/09 - 9/30/09
Basis swap		450,000	$	0.89	(c)	10/1/09 - 12/31/09
Basis swap		8,400,000	$	0.85	(c)	1/1/10 - 12/31/10
Basis swap		1,800,000	$	0.87	(c)	1/1/11 - 3/31/11
Basis swap		5,400,000	$	0.76	(c)	4/1/11 - 12/31/11

(a)	The index prices for the oil price swaps and collars 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.

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     In October 2009, we entered into the following oil and natural gas price swaps to hedge an additional portion of our estimated future production:

	Aggregate		Index			Contract
	Volume		Price			Period
Oil (volumes in Bbls):
Price swap		540,000	$	80.33	(a)	1/1/10 - 12/31/10
Natural gas (volumes in MMBtus):
Price swap		1,504,000	$	6.11	(b)	1/1/10 - 12/31/10

(a)	The index price for the oil price swap is 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.

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Results of Operations

     The following table presents selected volume and price information for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Net production volumes:
Oil (MBbl)		1,912		1,247		5,430		3,033
Natural gas (MMcf)		5,753		3,944		16,122		10,395
Total (MBoe)		2,871		1,904		8,117		4,766
Average daily production volumes:
Oil (Bbl)		20,783		13,554		19,890		11,069
Natural gas (Mcf)		62,533		42,870		59,055		37,938
Total (Boe)		31,205		20,699		29,733		17,392
Average prices:
Oil, without hedges (Bbl)	$	63.44	$	114.44	$	53.00	$	110.29
Oil, with hedges(a) (Bbl)	$	63.44	$	104.73	$	53.00	$	99.51
Natural gas, without hedges (Mcf)	$	5.60	$	10.12	$	4.90	$	10.87
Natural gas, with hedges(a) (Mcf)	$	5.60	$	10.11	$	4.90	$	10.84
Total, without hedges (Boe)	$	53.46	$	95.91	$	45.19	$	93.89
Total, with hedges(a) (Boe)	$	53.46	$	89.53	$	45.19	$	86.98

(a) These prices do not reflect the cash receipts/payments related to the oil and natural gas derivatives that were not designated as hedges and are reflected in (gain) loss on derivatives not designated as hedges in our statements of operations. If the cash receipts/payments related to the oil and natural gas derivatives that were not designated as hedges were included in our oil and natural gas sales our oil and natural gas prices would be as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Oil (Bbl)	$	70.75	$	95.24	$	65.96	$	90.35
Natural gas (Mcf)	$	6.19	$	9.87	$	5.48	$	10.71
Total (Boe)	$	59.51	$	82.81	$	55.00	$	80.86

     The presentation above provides the full effect of our oil and natural gas derivatives program without consideration for the financial presentation of the cash receipts/payments from the oil and natural gas derivatives.

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Three months ended September 30, 2009, compared to three months ended September 30, 2008

     Oil and natural gas revenues.Revenue from oil and natural gas operations was $153.5 million for the three months ended September 30, 2009, a decrease of $17.0 million (10 percent) from $170.5 million for the three months ended September 30, 2008. This decrease was primarily due to substantial decreases in realized oil and natural gas prices, offset by increased production (i) as a result of the acquisition of the Henry Properties on July 31, 2008 and (ii) due to successful drilling efforts during 2008 and 2009. Specifically, the:

• average realized oil price (after giving effect to hedging activities) was $63.44 per Bbl during the three months ended September 30, 2009, a decrease of 39 percent from $104.73 per Bbl during the three months ended September 30, 2008;

• total oil production was 1,912 MBbl for the three months ended September 30, 2009, an increase of 665 MBbl (53 percent) from 1,247 MBbl for the three months ended September 30, 2008;

• average realized natural gas price (after giving effect to hedging activities) was $5.60 per Mcf during the three months ended September 30, 2009, a decrease of 45 percent from $10.11 per Mcf during the three months ended September 30, 2008; and

• total natural gas production was 5,753 MMcf for the three months ended September 30, 2009, an increase of 1,809 MMcf (46 percent) from 3,944 MMcf for the three months ended September 30, 2008.

     Hedging activities.The oil and natural gas prices that we report are based on the market price received for the commodities adjusted to give effect to the results of our cash flow hedging activities. We utilize commodity derivative instruments in order to (i) reduce the effect of the volatility of price changes on the commodities we produce and sell, (ii) support our capital budget and expenditure plans and (iii) support the economics associated with acquisitions.

     Currently, we do not designate our derivative instruments to qualify for hedge accounting. Accordingly, we reflect the changes in the fair value of our derivative instruments in the statements of operations as (gain) loss on derivatives not designated as hedges. All of our remaining hedges that historically qualified or were dedesignated from hedge accounting were settled in 2008.

     The following is a summary of the effects of commodity hedges that qualify for hedge accounting treatment for the three months ended September 30, 2008:

	Oil Hedges			Natural Gas Hedges
	Three Months Ended			Three Months Ended
(dollars in thousands)	September 30, 2008			September 30, 2008
Hedging revenue decrease	$	(12,111	)	$	(38	)
Hedged volumes (Bbls and MMBtus, respectively)		239,000			1,242,000

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     Production expenses.The following tables provide the components of our total oil and natural gas production costs for the three months ended September 30, 2009 and 2008:

	Three Months Ended September 30,
	2009				2008
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Lease operating expenses	$	13,573	$	4.73	$	12,338	$	6.48
Taxes:
Ad valorem		954		0.33		792		0.42
Production		10,682		3.72		13,734		7.21
Workover costs		230		0.08		177		0.09
Total oil and gas production expenses	$	25,439	$	8.86	$	27,041	$	14.20

     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 $2.3 million ($.79 per Boe) related to overestimate of costs in the prior periods.

     Lease operating expenses were $13.6 million ($4.73 per Boe) for the three months ended September 30, 2009, an increase of $1.3 million (11 percent) from $12.3 million ($6.48 per Boe) for the three months ended September 30, 2008. The total increase in absolute amounts, taking into consideration details in the preceding paragraph, in lease operating expenses is due to (i) the wells acquired in the Henry Properties acquisition and (ii) our wells successfully drilled and completed in 2008 and 2009. The decrease in lease operating expenses on a per unit basis, taking into consideration details in the preceding paragraph, is due to (i) increased volumes from our successful drilling program in 2008 and 2009 that has allowed economies of scale in our cost structure and (ii) cost reductions in the services and supplies primarily as a result of the recently lower commodity prices, offset by the wells acquired in the Henry Properties acquisition, which have a higher per unit cost as compared to our historical per unit cost.

     Ad valorem taxes have increased primarily as a result of the Henry Properties acquisition, which were highly concentrated in Texas, a state which has a higher ad valorem tax rate than New Mexico, where substantially all of our properties prior to the acquisition were located.

     Production taxes per unit of production were $3.72 per Boe during the three months ended September 30, 2009, a decrease of 48 percent from $7.21 per Boe during the three months ended September 30, 2008. The decrease is directly related to the decrease in commodity prices offset by the increase in oil and natural gas revenues related to increased production volumes. Over the same period, our Boe prices (before the effects of hedging) decreased 44 percent.

     Workover expenses were approximately $0.2 million for the three months ended September 30, 2009 and 2008. The 2008 and 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 three months ended September 30, 2009 and 2008:

	Three Months Ended September 30,
(in thousands)	2009		2008
Geological and geophysical	$	2,120	$	111
Exploratory dry holes		474		2,779
Leasehold abandonments and other		182		13,934
Total exploration and abandonments	$	2,776	$	16,824

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     Our geological and geophysical expense during the three months ended September 30, 2009 is primarily attributable to continued seismic activity in our Lower Abo emerging play. During the three months ended September 30, 2008, our geological and geophysical expense was primarily attributable to a comprehensive seismic survey on our New Mexico shelf properties which was initiated in December 2007 and completed in 2008.

     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. Our exploratory dry hole expense during the three months ended September 30, 2008 is primarily attributable to an unsuccessful operated exploratory well located in our emerging plays area in Texas.

     For the three months ended September 30, 2009, we recorded approximately $0.2 million of leasehold abandonments, which relates primarily to the write-off of a prospect in our New Mexico Permian area and a prospect in our Texas Permian area.For the three months ended September 30, 2008, we recorded $13.9 million of leasehold abandonments, which were primarily related to our Western Delaware Basin acreage and a portion of our Fayetteville acreage in Arkansas.

     Depreciation, depletion and amortization expense.The following table provides components of our depreciation, depletion and amortization expense for the three months ended September 30, 2009 and 2008:

	Three Months Ended September 30,
	2009				2008
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties	$	53,824	$	18.75	$	31,729	$	16.66
Depreciation of other property and equipment		624		0.22		473		0.25
Amortization of intangible asset — operating rights		387		0.13		326		0.17
Total depletion, depreciation and amortization	$	54,835	$	19.10	$	32,528	$	17.08
Crude oil price used to estimate proved oil reserves at period end	$	67.00			$	97.00
Natural gas price used to estimate proved gas reserves at period end	$	3.30			$	7.12

     Depletion of proved oil and natural gas properties was $53.8 million ($18.75 per Boe) for the three months ended September 30, 2009, an increase of $22.1 million from $31.7 million ($16.66 per Boe) for the three months ended September 30, 2008. The increase in depletion expense, on a total and a per Boe basis, was primarily due to (i) the Henry Properties acquisition, for which the depletion rate was higher than that of our historical assets, (ii) capitalized costs associated with new wells that were successfully drilled and completed in 2008 and 2009 and (iii) the decrease in the oil and natural gas prices between the years utilized to determine proved reserves.

     The amortization of the intangible asset is a result of the value assigned to the operating rights that we acquired in the Henry Properties acquisition. 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 to downward adjustments to the economically recoverable resource potential associated with declines in commodity prices and well performance, we recognized a non-cash charge against earnings of $1.1 million during the three months ended September 30, 2009, which was primarily attributable to a downward revision of proved reserves primarily related to a property in our New Mexico Permian area. For the three months ended September 30, 2008, we recognized a non-cash charge against earnings of $2.8 million, which was comprised primarily of a property in our New Mexico Permian area.

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     General and administrative expenses.The following table provides components of our general and administrative expenses for the three months ended September 30, 2009 and 2008:

	Three Months Ended September 30,
	2009						2008
				Per						Per
(in thousands, except per unit amounts)	Amount			Boe			Amount			Boe
General and administrative expenses — recurring	$	10,986		$	3.83		$	8,611		$	4.52
Non-recurring bonus paid to former Henry Entities’ employees		2,369			0.83			2,367			1.24
Non-cash stock-based compensation — stock options		1,315			0.46			1,209			0.63
Non-cash stock-based compensation — restricted stock		1,233			0.43			716			0.38
Less: Third-party operating fee reimbursements		(3,188	)		(1.11	)		(2,125	)		(1.12	)
Total general and administrative expenses	$	12,715		$	4.44		$	10,778		$	5.65

     General and administrative expenses were $12.7 million ($4.44 per Boe) for the three months ended September 30, 2009, an increase of $1.9 million (18 percent) from $10.8 million ($5.65 per Boe) for the three months ended September 30, 2008. The increase in general and administrative expenses during the three months ended September 30, 2009 over 2008 was primarily due to (i) an increase in non-cash stock-based compensation and (ii) an increase in the number of employees and related personnel expenses, partially offset by an increase in third-party operating fee reimbursements.

     In connection with the Henry Entities acquisition, we agreed to pay certain of our employees, who were formerly Henry Entities’ employees, a predetermined bonus amount, in addition to the compensation we pay these employees, over the two years following the acquisition. Since these employees will earn this bonus over the two years, we are reflecting the cost in our general and administrative costs as non-recurring, as it is not controlled by us. See Note K of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited) “ for additional information related to this bonus.

     We earn reimbursements as operator of certain oil and natural gas properties in which we own interests. As such, we earned reimbursements of $3.2 million and $2.1 million during the three months ended September 30, 2009 and 2008, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations. The increase in this reimbursement is primarily related to the Henry Properties acquisition, as we own a lower working interest in these operated properties compared to our historical property base, so we receive a larger third-party reimbursement as compared to our historical property base.

     Bad debt expense.On May 20, 2008, we entered into a short-term purchase agreement with an oil purchaser to buy a portion of our oil affected as a result of a New Mexico refinery shut down due to repairs. On July 22, 2008, this purchaser declared bankruptcy. We fully reserved the receivable amount due from this purchaser of approximately $1.1 million during the three months ended September 30, 2008, and are pursuing our claim in the bankruptcy proceedings.

     (Gain) loss on derivatives not designated as hedges.During the three months ended September 30, 2007, we determined that all of our natural gas commodity derivative contracts no longer qualified as hedges. Because we no longer considered these hedges to be highly effective, we discontinued hedge accounting for those existing hedges, prospectively, and during the period the hedges became ineffective. In addition, for our commodity and interest rate derivative contracts entered into after August 2007, we chose not to designate any of these contracts as hedges. As a result, any changes in fair value and any cash settlements related to these contracts are recorded in earnings during the related period. All amounts previously recorded in accumulated other comprehensive income were reclassified to earnings prior to 2009.

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     The following table sets forth the cash receipts for settlements and the non-cash mark-to-market adjustment for the derivative contracts not designated as hedges for the three months ended September 30, 2009 and 2008:

	Three Months Ended September 30,
(in thousands)	2009			2008
Cash payments (receipts):
Commodity derivatives — oil	$	(13,971	)	$	11,837
Commodity derivatives — natural gas		(3,395	)		946
Financial derivatives — interest		1,241			—
Mark-to-market (gain) loss:
Commodity derivatives — oil		12,821			(160,148	)
Commodity derivatives — natural gas		8,442			(15,947	)
Financial derivatives — interest		2,645			—
(Gain) loss on derivatives not designated as hedges	$	7,783		$	(163,312	)

     Interest expense.Interest expense was $6.8 million for the three months ended September 30, 2009, a decrease of $3.5 million from $10.3 million for the three months ended September 30, 2008. The weighted average interest rate for the three months ended September 30, 2009 and 2008 was 3.2 percent and 4.2 percent, respectively. The weighted average debt balance during the three months ended September 30, 2009 and 2008 was approximately $664.6 million and $541.4 million, respectively.

     The increase in weighted average debt balance during the three months ended September 30, 2009 was due primarily to borrowings in July 2008 for the acquisition of the Henry Properties. The decrease in interest expense is due to a decrease in the weighted average interest rate offset by an increase in the weighted average debt balance. The decrease in the weighted average interest rate is primarily due to an improvement in market interest rates.

     The three months ended September 30, 2009, includes twelve days of interest on the $300 million of 8.625% senior notes issued in September 2009. Currently, the interest rate associated with the senior notes is higher than the credit facility, which will result in us having higher absolute interest rates in the foreseeable future.

     Income tax provisions.We recorded income tax expense of $21.8 million and $91.0 million for the three months ended September 30, 2009 and 2008, respectively. The effective income tax rate for the three months ended September 30, 2009 and 2008 was 52.5 percent and 39.1 percent, respectively. At September 30, 2009, we estimate our annual effective tax rate to be approximately 31.0 percent (which is discussed later in this document) and at June 30, 2009 we estimated our annual effective tax rate to be 42.1 percent. 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, 2009 includes approximately $8.9 million of tax expense associated with the effects of the change in the six months ended June 30, 2009 and nine months ended September 30, 2009 estimated annual effective tax rates.

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Nine months ended September 30, 2009, compared to nine months ended September 30, 2008

     Oil and natural gas revenues.Revenue from oil and natural gas operations was $366.8 million for the nine months ended September 30, 2009, a decrease of $47.8 million (12 percent) from $414.6 million for the nine months ended September 30, 2008. This decrease was primarily due to substantial decreases in realized oil and natural gas prices, offset by increased production (i) as a result of the acquisition of the Henry Properties on July 31, 2008 and (ii) due to successful drilling efforts during 2008 and 2009. Specifically, the:

• average realized oil price (after giving effect to hedging activities) was $53.00 per Bbl during the nine months ended September 30, 2009, a decrease of 47 percent from $99.51 per Bbl during the nine months ended September 30, 2008;

• total oil production was 5,430 MBbl for the nine months ended September 30, 2009, an increase of 2,397 MBbl (79 percent) from 3,033 MBbl for the nine months ended September 30, 2008;

• average realized natural gas price (after giving effect to hedging activities) was $4.90 per Mcf during the nine months ended September 30, 2009, a decrease of 55 percent from $10.84 per Mcf during the nine months ended September 30, 2008; and

• total natural gas production was 16,122 MMcf for the nine months ended September 30, 2009, an increase of 5,727 MMcf (55 percent) from 10,395 MMcf for the nine months ended September 30, 2008.

     Hedging activities.The oil and natural gas prices that we report are based on the market price received for the commodities adjusted to give effect to the results of our cash flow hedging activities. We utilize commodity derivative instruments in order to (i) reduce the effect of the volatility of price changes on the commodities we produce and sell, (ii) support our capital budget and expenditure plans and (iii) support the economics associated with acquisitions.

     Currently, we do not designate our derivative instruments to qualify for hedge accounting. Accordingly, we reflect the changes in the fair value of our derivative instruments in the statements of operations as (gain) loss on derivatives not designated as hedges. All of our remaining hedges that historically qualified or were dedesignated from hedge accounting were settled in 2008.

     The following is a summary of the effects of commodity hedges that qualify for hedge accounting treatment for the nine months ended September 30, 2008:

	Oil Hedges			Natural Gas Hedges
	Nine Months Ended			Nine Months Ended
(dollars in thousands)	September 30, 2008			September 30, 2008
Hedging revenue decrease	$	(32,684	)	$	(260	)
Hedged volumes (Bbls and MMBtus, respectively)		712,000			3,699,000

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     Production expenses.The following tables provide the components of our total oil and natural gas production costs for the nine months ended September 30, 2009 and 2008:

	Nine Months Ended September 30,
	2009				2008
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Lease operating expenses	$	45,867	$	5.65	$	28,576	$	6.00
Taxes:
Ad valorem		3,445		0.42		1,798		0.38
Production		26,047		3.21		34,842		7.31
Workover costs		663		0.08		699		0.15
Total oil and gas production expenses	$	76,022	$	9.36	$	65,915	$	13.84

     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.

     Lease operating expenses were $45.9 million ($5.65 per Boe) for the nine months ended September 30, 2009, an increase of $17.3 million (60 percent) from $28.6 million ($6.00 per Boe) for the nine months ended September 30, 2008. The total increase in absolute amounts in lease operating expenses is due to (i) the wells acquired in the Henry Properties acquisition and (ii) our wells successfully drilled and completed in 2008 and 2009. The decrease in lease operating expenses on a per unit basis is due to (i) increased volumes from our successful drilling program in 2008 and 2009 that has allowed economies of scale in our cost structure and (ii) cost reductions in the services and supplies primarily as a result of the recently lower commodity prices, offset by the wells acquired in the Henry Properties acquisition, which have a higher per unit cost as compared to our historical per unit cost.

     Ad valorem taxes have increased primarily as a result of the Henry Properties acquisition, which were highly concentrated in Texas, a state which has a higher ad valorem tax rate than New Mexico, where substantially all of our properties prior to the acquisition were located.

     Production taxes per unit of production were $3.21 per Boe during the nine months ended September 30, 2009, a decrease of 56 percent from $7.31 per Boe during the nine months ended September 30, 2008. The decrease is directly related to the decrease in commodity prices offset by the increase in oil and natural gas revenues related to increased volumes. Over the same period, our Boe prices (before the effects of hedging) decreased 52 percent.

     Workover expenses were approximately $0.7 million for both the nine months ended September 30, 2009 and 2008. The 2009 and 2008 amounts related primarily to workovers in the 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, 2009 and 2008:

	Nine Months Ended September 30,
(in thousands)	2009		2008
Geological and geophysical	$	3,245	$	2,428
Exploratory dry holes		2,340		2,778
Leasehold abandonments and other		4,610		15,082
Total exploration and abandonments	$	10,195	$	20,288

     Our geological and geophysical expense during the nine months ended September 30, 2009 is primarily attributable to continued seismic activity in our Lower Abo emerging play. During the nine months ended September 30, 2008, our geological and geophysical

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expense was primarily attributable to a comprehensive seismic survey on our New Mexico shelf properties which was initiated in December 2007 and completed in 2008.

     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 Texas Permian area. Our exploratory dry hole expense during the nine months ended September 30, 2008 was primarily attributable to an unsuccessful operated exploratory well located in our Texas Permian area.

     For the nine months ended September 30, 2009, we recorded approximately $4.6 million of leasehold abandonments, which relate primarily to the write-off of four prospects in our New Mexico Permian area and three prospects in our Texas Permian area.For the nine months ended September 30, 2008, we recorded $15.1 million of leasehold abandonments, which were primarily related to two prospects in our Texas and Arkansas emerging plays 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, 2009 and 2008:

	Nine Months Ended September 30,
	2009				2008
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties	$	154,819	$	19.07	$	74,239	$	15.58
Depreciation of other property and equipment		1,998		0.25		1,257		0.26
Amortization of intangible asset — operating rights		1,168		0.14		326		0.07
Total depletion, depreciation and amortization	$	157,985	$	19.46	$	75,822	$	15.91
Crude oil price used to estimate proved oil reserves at period end	$	67.00			$	97.00
Natural gas price used to estimate proved gas reserves at period end	$	3.30			$	7.12

     Depletion of proved oil and natural gas properties was $154.8 million ($19.07 per Boe) for the nine months ended September 30, 2009, an increase of $80.6 million from $74.2 million ($15.58 per Boe) for the nine months ended September 30, 2008. The increase in depletion expense, on a total and per Boe basis, was primarily due to (i) the Henry Properties acquisition, for which the depletion rate was higher than that of our historical assets, (ii) capitalized costs associated with new wells that were successfully drilled and completed in 2008 and 2009 and (iii) the decrease in the oil and natural gas prices between the years utilized to determine proved reserves.

     The amortization of the intangible asset is a result of the value assigned to the operating rights that we acquired in the Henry Properties acquisition. 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 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 $9.7 million during the nine months ended September 30, 2009, which was primarily attributable to natural gas related properties in our New Mexico Permian area. For the nine months ended September 30, 2008, we recognized a non-cash charge against earnings of $2.8 million, which was comprised primarily of a property in our New Mexico Permian area.

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     General and administrative expenses.The following table provides components of our general and administrative expenses for the nine months ended September 30, 2009 and 2008:

	Nine Months Ended September 30,
	2009						2008
				Per						Per
(in thousands, except per unit amounts)	Amount			Boe			Amount			Boe
General and administrative expenses — recurring	$	32,925		$	4.06		$	22,352		$	4.69
Non-recurring bonus paid to former Henry Entities’ employees		7,680			0.95			2,367			0.50
Non-cash stock-based compensation — stock options		3,228			0.40			3,376			0.71
Non-cash stock-based compensation — restricted stock		3,433			0.42			1,578			0.33
Less: Third-party operating fee reimbursements		(8,633	)		(1.06	)		(2,629	)		(0.54	)
Total general and administrative expenses	$	38,633		$	4.77		$	27,044		$	5.69

     General and administrative expenses were $38.6 million ($4.77 per Boe) for the nine months ended September 30, 2009, an increase of $11.6 million (43 percent) from $27.0 million ($5.69 per Boe) for the nine months ended September 30, 2008. The increase in general and administrative expenses during the nine months ended September 30, 2009 over 2008 was primarily due to (i) the non-recurring bonus paid to former Henry Entities’ employees, (ii) an increase in non-cash stock-based compensation and (iii) an increase in the number of employees and related personnel expenses, partially offset by an increase in third-party operating fee reimbursements.

     In connection with the Henry Entities acquisition, we agreed to pay certain of our employees, who were formerly Henry Entities’ employees, a predetermined bonus amount, in addition to the compensation we pay these employees, over the two years following the acquisition. Since these employees will earn this bonus over the two years, we are reflecting the cost in our general and administrative costs as non-recurring, as it is not controlled by us. See Note K of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited) “ for additional information related to this bonus.

     We earn reimbursements as operator of certain oil and natural gas properties in which we own interests. As such, we earned reimbursements of $8.6 million and $2.6 million during the nine months ended September 30, 2009 and 2008, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations. The increase in this reimbursement is primarily related to the Henry Properties acquisition, as we own a lower working interest in these operated properties compared to our historical property base, so we receive a larger third-party reimbursement as compared to our historical property base.

     Bad debt expense.On May 20, 2008, we entered into a short-term purchase agreement with an oil purchaser to buy a portion of our oil affected as a result of a New Mexico refinery shut down due to repairs. On July 22, 2008, this purchaser declared bankruptcy. We fully reserved the receivable amount due from this purchaser of approximately $2.9 million as of September 30, 2008, and are pursuing our claim in the bankruptcy proceedings.

     (Gain) loss on derivatives not designated as hedges.During the nine months ended September 30, 2007, we determined that all of our natural gas commodity derivative contracts no longer qualified as hedges. Because we no longer considered these hedges to be highly effective, we discontinued hedge accounting for those existing hedges, prospectively, and during the period the hedges became ineffective. In addition, for our commodity and interest rate derivative contracts entered into after August 2007, we chose not to designate any of these contracts as hedges. As a result, any changes in fair value and any cash settlements related to these contracts are recorded in earnings during the related period. All amounts previously recorded in accumulated other comprehensive income were reclassified to earnings prior to 2009.

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     The following table sets forth the cash receipts for settlements and the non-cash mark-to-market adjustment for the derivative contracts not designated as hedges for the nine months ended September 30, 2009 and 2008:

	Nine Months Ended September 30,
(in thousands)	2009			2008
Cash payments (receipts):
Commodity derivatives — oil	$	(70,383	)	$	27,802
Commodity derivatives — natural gas		(9,227	)		1,368
Financial derivatives — interest		2,020			—
Mark-to-market (gain) loss:
Commodity derivatives — oil		156,920			(71,248	)
Commodity derivatives — natural gas		13,460			(1,600	)
Financial derivatives — interest		1,645			—
(Gain) loss on derivatives not designated as hedges	$	94,435		$	(43,678	)

     Interest expense.Interest expense was $17.4 million for the nine months ended September 30, 2009, a decrease of $2.4 million from $19.8 million for the nine months ended September 30, 2008. The weighted average interest rate for the nine months ended September 30, 2009 and 2008 was 2.7 percent and 5.1 percent, respectively. The weighted average debt balance during the nine months ended September 30, 2009 and 2008 was approximately $666.9 million and $389.9 million, respectively.

     The increase in weighted average debt balance during the nine months ended September 30, 2009 was due primarily to borrowings in July 2008 for the acquisition of the Henry Properties. The decrease in interest expense is due to a decrease in the weighted average interest rate offset by an increase in the weighted average debt balance. The decrease in the weighted average interest rate is primarily due to an improvement in market interest rates.

     The three months ended September 30, 2009, includes twelve days of interest on the $300 million of 8.625% senior notes issued in September 2009. Currently, the interest rate associated with the senior notes is higher than the credit facility, which will result in us having higher absolute interest rates in the foreseeable future.

     Income tax provisions.We recorded an income tax benefit of $12.0 million and income tax expense of $96.2 million for the nine months ended September 30, 2009 and 2008, respectively. The effective income tax rate for the nine months ended September 30, 2009 and 2008 was 31.0 percent and 39.1 percent, respectively. The lower annual effective tax rate in 2009 compared to 2008 is primarily due to the estimated annual 2009 permanent tax differences compared to the related current estimated annual pre-tax book income. The estimated annual effective tax rate for 2009 at June 30, 2009 was 42.1 percent based on the then estimated 2009 annual permanent tax differences and pre-tax book income. If the actual 2009 pre-tax book income is larger than the current estimate of 2009 pre-tax book income we would expect the annual effective tax rate to be higher than the current estimate of 31.0 percent.

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 cost incurred on oil and natural gas properties, excluding acquisitions and asset retirement obligations, during the three months ended September 30, 2009 and 2008 totaled $91.0 million and $108.2 million, respectively, and $293.7 million and $229.5 million for the nine months ended September 30, 2009 and 2008, respectively. These expenditures were primarily funded by cash flow from operations (including effects of derivative cash receipts/payments).

     On November 6, 2008, our board of directors approved a capital budget for 2009 of up to approximately $500 million. The capital budget is predicated on funding it substantially within cash flow. In January 2009, in light of the drop in commodity prices, we took actions to reduce our capital activities to a level that would allow us to fund our capital expenditures substantially within our cash flow, which at the time resulted in estimated annual capital expenditures of approximately $300 million. Currently, based on current

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capital costs and commodity prices we estimate our capital expenditures to be approximately $400 million for 2009, which we believe we can substantially fund within our cash flow. We will continue to monitor our capital expenditures, at least on a quarterly basis, in relation to our cash flow and expect to adjust our activity and capital spending level based on changes in commodity prices and the cost of goods and services and other considerations. For clarity purposes we view “our” cash flow as our cash flow from operations before changes in working capital and we include the cash payments/receipts on our derivatives that are included in our investing activities.

     On November 5, 2009, our board of directors approved a capital budget for 2010 of approximately $506 million. The capital budget is predicated on us funding it substantially within our cash flow. If commodity prices decline, below those at the time of the capital budget approval, and considering other factors that may change, we expect we would adjust our spending such that we spend substantially within our cash flow.

     Other than the purchase of leasehold acreage and other miscellaneous property interests, our 2009 and 2010 capital budgets are exclusive of acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek to acquire oil and natural gas properties that provide opportunities for the addition of reserves and production through a combination of exploitation, development, high-potential exploration and control of operations and that will allow us to apply our operating expertise.

     Although we cannot provide any assurance, we believe that our available cash and cash flows will be sufficient to fund our remaining 2009 and 2010 capital expenditures, 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 2009 and 2010 capital budgets.

     Acquisitions.Our expenditures for acquisitions of proved and unproved properties during the three months ended September 30, 2009 and 2008 totaled $7.2 million and $813.9 million, respectively, and $10.7 million and $815.2 million for the nine months ended September 30, 2009 and 2008, respectively. The Henry Properties acquisition in July 2008 was primarily funded by a private placement of our common stock and borrowings under our credit facility.

     Contractual obligations.Our contractual obligations include long-term debt, operating lease obligations, drilling commitments (including commitments to pay day rates for drilling rigs), employment agreements, contractual bonus payments, derivative obligations and other liabilities.

     We had the following contractual obligations at September 30, 2009:

	Payments due by period
			Less than		1 - 3		3 - 5		More than
(in thousands)	Total		1 year		years		years		5 years
Long-term debt(a)	$	650,000	$	—	$	—	$	350,000	$	300,000
Operating lease obligations(b)		7,850		1,073		2,163		4,614		—
Drilling commitments(c)		2,805		2,805		—		—		—
Employment agreements with executive officers (d)		4,421		1,965		2,456		—		—
Henry Entities bonus obligation (e)		8,233		8,233		—		—		—
Derivative liabilities(f)		39,717		23,158		16,559		—		—
Asset retirement obligations (g)		14,134		1,473		360		443		11,858
Total contractual cash obligations	$	727,160	$	38,707	$	21,538	$	355,057	$	311,858

(a) See Note J of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for information regarding future interest payment obligations on the 8.625% unsecured senior notes. The amounts included in the table above represent principal maturities only.

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(b)	See Note K of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).”
(c)	Consists of daywork drilling contracts related to drilling rigs contracted through June 30, 2010. See Note K of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).”
(d)	Represents amounts of cash compensation we are obligated to pay to our executive officers under employment agreements assuming such employees continue to serve the entire term of their employment agreement and their cash compensation is not adjusted.
(e)	Represents bonuses we agreed to pay certain employees of the Henry Entities at each of the first and second anniversaries of the closing of the Henry Properties acquisition. The first such anniversary bonus payment was made on July 31, 2009. See Note K of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).”
(f)	Derivative obligations represent only the liability positions for our commodity and interest rate derivatives that were valued at September 30, 2009. The ultimate settlement amounts of our derivative obligations are unknown because they are subject to continuing market risk. See Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” regarding our derivative obligations.
(g)	Amounts represent costs related to expected oil and gas property abandonments related to proved reserves by period, net of any future accretion. See Note E of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).”

     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 derivative cash receipts/payments presented in our investing activities) and financing provided by our credit facility. We believe that funds from our cash flows and our credit facility should be sufficient to meet both our short-term working capital requirements and our 2009 and 2010 capital expenditure plans.

     Cash flow from operating activities.Our net cash provided by operating activities was $232.1 million and $319.4 million for the nine months ended September 30, 2009 and 2008, respectively. The decrease in operating cash flows during the nine months ended September 30, 2009 over 2008 was principally due to (i) decreases in average realized oil and natural gas prices, offset by increased production, (ii) increases in oil and natural gas production costs and general and administrative expenses and (iii) uses of funds associated with working capital.

     Cash flow used in investing activities.During the nine months ended September 30, 2009 and 2008, we invested $316.8 million and $800.6 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 substantially lower during the nine months ended September 30, 2009 over 2008, due to (i) the Henry acquisition occurring in the third quarter of 2008 and (ii) the receipts/payments associated with derivatives not designated as hedges offset by an increase in our exploration and development activities.

     Cash flow from financing activities.Net cash provided by financing activities was $7.7 million and $540.0 million for the nine months ended September 30, 2009 and 2008, respectively. During the nine months ended September 30, 2008, we borrowed funds under our credit facility and issued approximately 8.3 million shares of our common stock to fund the Henry acquisition.

     On September 18, 2009, we issued $300 million in principal amount of 8.625% senior notes due 2017 at 98.578% of par. The 8.625% senior notes will mature on October 1, 2017 and interest is paid in arrears semi-annually on April 1 and October 1 beginning April 1, 2010. We used the net proceeds of $288.2 million (net of related estimated offering costs) to repay a portion of the borrowings under our credit facility. The senior notes are senior unsecured obligations of ours and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness.

     We issued the senior notes to (i) extend the maturities of our debt to better match the long-lived nature of our assets, (ii) increase liquidity under our credit facility and (iii) reduce our dependency on bank debt.

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     Pursuant to the terms of our credit facility (described below), our borrowing base was to be reduced by $0.30 for every dollar of new indebtedness evidenced by unsecured senior notes or unsecured senior subordinated notes that we issue. As a result of this provision, the borrowing base under our credit facility would have been reduced by $90 million due to our issuance and sale of the senior notes. However, we received waivers of this provision from lenders representing approximately 95.4% of our borrowing base, resulting in an actual reduction of approximately $4.1 million in our borrowing base, which reduced our borrowing base to $955.9 million.

     Our credit facility, as amended, has a maturity date of July 31, 2013. At September 30, 2009, we had letters of credit outstanding under the credit facility of approximately $25,000 and our availability to borrow additional funds was approximately $605.9 million. In October 2009, the lenders reaffirmed our $955.9 million borrowing base under the credit facility until the next scheduled borrowing base redetermination in April 2010. 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, 2009) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). At September 30, 2009, the interest rates of Eurodollar rate advances and JPM Prime Rate advances vary, 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, 2009, we pay commitment fees on the unused portion of the available borrowing base of 50 basis points per annum.

     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.

     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 economy has experienced and continues to experience volatility, which continues to have an adverse impact on the financial markets.

     At September 30, 2009, we had $605.9 million of available borrowing capacity under our credit facility. Our credit facility is backed by a syndicate of 21 banks. Even in light of the current volatility in the financial markets, we currently believe that the lenders under our credit facility have the ability to fund additional borrowings we may need for our business.

     We currently pay floating rate interest under our credit facility and we are unable to predict, especially in light of the current 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 or to reduce our exposure to the volatility of interest rates.

     In the current financial markets, we do not believe that we could refinance our credit facility and obtain comparable terms. Since our credit facility matures in July 2013, we have no immediate need to seek refinancing of our credit facility.

     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, 2009, we had $15.7 million of cash on hand.

     At September 30, 2009, the borrowing base under our credit facility was $955.9 million (which was reaffirmed in October 2009), which provided us with $605.9 million of available borrowing capacity. Our borrowing base is redetermined semi-annually, with the next redetermination occurring in April 2010. In addition to such semi-annual redeterminations, our lenders may request one additional redetermination during any twelve-month period. In general, redeterminations are based upon a number of factors,

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including commodity prices and reserve levels. Upon a redetermination, our borrowing base could be substantially reduced. In light of the current 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, 2009 was $1,958.4 million, consisting of debt of $645.7 million and stockholders’ equity of $1,312.7 million. Our debt to book capitalization was 33 percent and 32 percent at September 30, 2009 and December 31, 2008, respectively. Our ratio of current assets to current liabilities was 0.74 to 1.00 at September 30, 2009 as compared to 1.03 to 1.00 at December 31, 2008.

     Inflation and changes in prices.Our revenues, the value of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the three months ended September 30, 2009, we received an average of $63.44 per barrel of oil and $5.60 per Mcf of natural gas before consideration of commodity derivative contracts compared to $114.44 per barrel of oil and $10.12 per Mcf of natural gas in the three months ended September 30, 2008. 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 have 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 continue to moderate during the remainder of 2009 as a result of the recent rapid diminution in prices for oil and natural gas from 2008 peaks.

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 three months ended September 30, 2009. See our disclosure of critical accounting policies in the consolidated financial statements on our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the United States Securities and Exchange Commission (“SEC”) on February 27, 2009.

Recent Accounting Pronouncements and Developments

     Recent accounting pronouncements:

     In June 2009, the Financial Accounting Standards Board (“FASB”) issued ASC 105-10 (formerly Statement of Financial Accounting Standards No. 168),Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. The FASB Accounting Standards Codification (the “Codification”) has become the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in accordance with Generally Accepted Accounting Principles (“GAAP”). All existing accounting standard documents are superseded by the Codification and any accounting literature not included in the Codification will not be authoritative. However, rules and interpretive releases of the SEC issued under the authority of federal securities laws will continue to be the source of authoritative generally accepted accounting principles for SEC registrants. Effective September 30, 2009, there will be no more references made to the superseded FASB standards in our consolidated financial statements. The Codification does not change or alter existing GAAP and, therefore, will not have an impact on our financial position, results of operations or cash flows.

     ASU 2009-05.In August 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2009-05,Fair Value Measurements and Disclosures (Topic 820)—Measuring Liabilities at Fair Value(“ASU 2009-05”).The FASB issued this update because some entities have expressed concern that there may be a lack of observable market information

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to measure the fair value of a liability. ASU 2009-05 is effective for the first reporting period beginning after August 28, 2009, with earlier application permitted. The guidance provides clarification on measuring liabilities at fair value when a quoted price in an active market is not available. In such circumstances, ASU 2009-05 specifies that a valuation technique should be applied that uses either the quote of the liability when traded as an asset, the quoted prices for similar liabilities or similar liabilities when traded as assets, or another valuation technique consistent with existing fair value measurement guidance. Examples of the alternative valuation methods include using a present value technique or a market approach, which is based on the amount at the measurement date that the reporting entity would pay to transfer the identical liability or would receive to enter into the identical liability. The guidance also states that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustments to other inputs relating to the existence of a restriction that prevents the transfer of the liability. We adopted ASU 2009-05 effective September 30, 2009, and the adoption did not have a significant impact on our consolidated financial statements.

     ASU 2009-11.In September 2009, the FASB issued ASU 2009-11,Extractive Activities — Oil and Gas: Amendment to Section 932-10-S99, which makes a technical correction in ASC 932-10-S99-5 related to an SEC Observer comment, regarding the accounting and disclosures for gas balancing arrangements. The ASU amends FASB ASC 932-10-S99-5 because the SEC staff has not taken a position on whether the entitlements method or sales method is preferable for gas-balancing arrangements as defined in FASB ASC 932-815-55-1 and FASB ASC 932-815-55-2 that do not meet the definition of a derivative.

           With the entitlements method, sales revenue is recognized to the extent of each well partner’s proportionate share of gas sold regardless of which partner sold the gas. Under the sales method, sales revenue is recognized for all gas sold by a partner even if the partner’s ownership is less than 100% of the gas sold.

     ASU 2009-11 included an instruction in FASB ASC 932-10-S99-5 that public companies must account for all significant gas imbalances consistently using one accounting method. Both the method and any significant amount of imbalances in units and value should be disclosed in regulatory filings. We currently account for all gas balances under the sales method and make all required disclosures.

     Recent developments in reserves reporting.In December 2008, the SEC released Final Rule,Modernization of Oil and Gas Reporting(the “Reserve Ruling”). The Reserve Ruling revises oil and natural gas reporting disclosures. The Reserve Ruling permits the use of new technologies to determine proved reserves estimates if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volume estimates. The Reserve Ruling will also allow, but not require, companies to disclose their probable and possible reserves to investors in documents filed with the SEC. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12-month period rather than a year-end price. The Reserve Ruling becomes effective for fiscal years ending on or after December 31, 2009. We are currently assessing the impact that adoption of the provisions of the Reserve Ruling will have on our financial position, results of operations and disclosures.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

     The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2008.

     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, 2009, 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. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Although we have not generally required our counterparties to provide collateral to support their obligation to us, we may, if circumstances dictate, require collateral in the future. In this manner, we reduce credit risk.

     Commodity price risk.We are exposed to market risk as the prices of oil and natural gas are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of oil and natural gas we have entered into, and may in the future enter into additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Our commodity price risk management activities could have the effect of reducing net income and the value of our common stock. An average increase in the commodity price of $10.00 per barrel of oil and $1.00 per Mcf for natural gas from the commodity prices at September 30, 2009, would have decreased the net unrealized value on our commodity price risk management contracts by approximately $91 million.

     At September 30, 2009, we had (i) an oil price collar and oil price swaps that settle on a monthly basis covering future oil production from July 1, 2009 through December 31, 2012 and (ii) a natural gas price swap, natural gas price collars and natural gas basis swaps covering future natural gas production from July 1, 2009 to December 31, 2011, see Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on the commodity derivative contracts. The average NYMEX oil futures price and average NYMEX natural gas futures prices for the three months ended September 30, 2009, was $68.24 per Bbl and $3.42 per MMBtu, respectively. At November 2, 2009, the NYMEX oil futures price and NYMEX natural gas futures price was $78.13 per Bbl and $4.82 per MMBtu, respectively. The decrease in oil and natural gas prices, should it continue during 2009, should increase the fair value asset of our commodity derivative contracts from their recorded balance at September 30, 2009. 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 fair value asset would be recorded in earnings as unrealized gains. However, an increase in the average NYMEX oil and natural gas futures price above those at September 30, 2009 would result in an decrease in fair value asset and unrealized losses 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 long-term 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.

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     At September 30, 2009, we had interest rate swaps on $300 million of notional principal that fixed the LIBOR interest rate (does not include 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, 2009, would have decreased our net unrealized value on our interest rate risk management contracts by approximately $2.1 million.

     We had total indebtedness of $350 million outstanding under our credit facility at September 30, 2009. The impact of a 1 percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $3.5 million.

     The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method during 2009. During 2009, we were party to commodity 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, 2009:

	Derivative Instruments Net Assets (Liabilities)(a)
(in thousands)	Commodities			Interest Rate			Total
Fair value of contracts outstanding at December 31, 2008	$	173,523		$	(1,083	)	$	172,440
Changes in fair values(b)		(90,770	)		(3,665	)		(94,435	)
Contract maturities		(79,610	)		2,020			(77,590	)
Fair value of contracts outstanding at September 30, 2009	$	3,143		$	(2,728	)	$	415

(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.

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Item 4. Controls and Procedures

     Evaluation of disclosure controls and procedures.The Company’s management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Exchange Act, the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this report. Based on that evaluation, the Company’s principal executive officer and principal financial officer concluded that the design and operation of the Company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

     We are party to the legal proceedings described under “Legal actions” in Note K of Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).” We are also party to other proceedings and claims incidental to our business. While many of these other matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to such 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

     There have been no material changes in the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008 and our Quarterly Reports on Form 10-Q for the three months ended March 31, 2009 and June 30, 2009.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

					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, 2009 - July 31, 2009		—	$	—		—
August 1, 2009 - August 31, 2009		3,039	$	32.88		—
September 1, 2009 - September 30, 2009		—	$	—		—

⁽¹⁾ Represents shares that were withheld by us to satisfy tax withholding obligations of certain executive officers that arose upon the lapse of restrictions on restricted stock.

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Item 6. Exhibits

Exhibit
Number		Exhibit
3.1		Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).
3.2		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		Indenture, dated September 18, 2009, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on September 22, 2009, and incorporated herein by reference).
4.2		First Supplemental Indenture, dated September 18, 2009, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on September 22, 2009, and incorporated herein by reference).
4.3		Form of 8.625% Senior Notes due 2017 (included in Exhibit 4.2).
10.1		Waiver agreement, effective as of September 18, 2009, among Concho Resources Inc. and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 22, 2009, and incorporated herein by reference).
31.1	(a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	(a)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	(b)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	(b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(a)	Filed herewith.
(b)	Furnished herewith.

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SIGNATURES

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

	CONCHO RESOURCES INC.
Date: November 5, 2009	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
		Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)

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EXHIBIT INDEX

Exhibit
Number		Exhibit
3.1		Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).
3.2		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		Indenture, dated September 18, 2009, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on September 22, 2009, and incorporated herein by reference).
4.2		First Supplemental Indenture, dated September 18, 2009, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on September 22, 2009, and incorporated herein by reference).
4.3		Form of 8.625% Senior Notes due 2017 (included in Exhibit 4.2).
10.1		Waiver agreement, effective as of September 18, 2009, among Concho Resources Inc. and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 22, 2009, and incorporated herein by reference).
31.1	(a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	(a)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	(b)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	(b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(a)	Filed herewith.
(b)	Furnished herewith.