Concho Resources (CXO) 10-Q 2015 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2015

or

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

For the transition period from to

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)

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

	(432) 683-7443
(Registrant’s telephone number, including area code)

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

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

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

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

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

Number of shares of the registrant’s common stock outstanding at November 2, 2015: 129,144,365 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	28
	Item 3. Quantitative and Qualitative Disclosures About Market Risk	50
	Item 4. Controls and Procedures	52
PART II – OTHER INFORMATION:		53
	Item 1. Legal Proceedings	53
	Item 1A. Risk Factors	53
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	54
	Item 6. Exhibits	55

i

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements and information contained in or incorporated by reference into this Quarterly Report on Form 10-Q (this “Quarterly Report”) that express a belief, expectation, or intention, or that are not statements of historical fact, are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our future financial position, operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events and their potential effect on us. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by any forward-looking statements. These forward-looking statements speak only as of the date of this Quarterly Report, or if earlier, as of the date they were made. We disclaim any obligation to update or revise these statements unless required by law, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Part II, Item 1A, Risk Factors” in this Quarterly Report, in our Annual Report on Form 10-K for the year ended December 31, 2014 and in our Current Reports on Form 8-K, as well as those factors summarized below:

·declines in the prices we receive for our oil and natural gas;

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

·drilling and operating risks, including risks related to properties where we do not serve as the operator;

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

·the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing and the export of oil and natural gas;

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

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

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

·disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver oil, natural gas liquids and natural gas and other processing and transportation considerations;

·the costs and availability of equipment, resources, services and personnel required to perform our drilling and operating activities;

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

·risks and liabilities associated with acquired properties or businesses;

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

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

·general economic and business conditions, either internationally or domestically;

·competition in the oil and natural gas industry; and

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

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

ii

PART I – FINANCIAL INFORMATION

Item 1.  Consolidated Financial Statements (Unaudited)

Consolidated Balance Sheets at September 30, 2015 and December 31, 2014	1
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2015 and 2014	2
Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2015	3
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2015 and 2014	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 amounts)					2015		2014
Assets
Current assets:
	Cash and cash equivalents			$	20	$	21
	Accounts receivable, net of allowance for doubtful accounts:
		Oil and natural gas			229,756		250,600
		Joint operations and other			220,137		409,665
	Derivative instruments				581,436		490,351
	Prepaid costs and other				39,332		37,759
			Total current assets		1,070,681		1,188,396
Property and equipment:
	Oil and natural gas properties, successful efforts method				15,682,799		13,867,831
	Accumulated depletion and depreciation				(4,681,106)		(3,790,953)
		Total oil and natural gas properties, net			11,001,693		10,076,878
	Other property and equipment, net				160,582		129,136
		Total property and equipment, net			11,162,275		10,206,014
Deferred loan costs, net					60,994		68,443
Intangible asset - operating rights, net					26,059		27,154
Inventory					21,688		14,435
Noncurrent derivative instruments					108,894		262,349
Other assets					76,971		33,172
	Total assets			$	12,527,562	$	11,799,963
Liabilities and Stockholders’ Equity
Current liabilities:
	Accounts payable - trade			$	26,801	$	20,380
	Bank overdrafts				109,741		92,541
	Revenue payable				185,732		238,098
	Accrued and prepaid drilling costs				303,331		718,300
	Deferred income taxes				197,632		162,566
	Other current liabilities				205,417		195,308
			Total current liabilities		1,028,654		1,427,193
Long-term debt					3,822,274		3,517,320
Deferred income taxes					1,409,684		1,438,185
Asset retirement obligations and other long-term liabilities					133,168		136,477
Commitments and contingencies (Note 9)
Stockholders’ equity:
	Common stock, $0.001 par value; 300,000,000 authorized; 120,594,183 and
		113,264,918 shares issued at September 30, 2015 and December 31, 2014, respectively			121		113
	Additional paid-in capital				3,818,673		3,027,412
	Retained earnings				2,346,429		2,279,741
	Treasury stock, at cost; 304,483 and 260,124 shares at September 30, 2015 and
		December 31, 2014, respectively			(31,441)		(26,478)
			Total stockholders’ equity		6,133,782		5,280,788
	Total liabilities and stockholders’ equity			$	12,527,562	$	11,799,963
The accompanying notes are an integral part of these consolidated financial statements.

1

Concho Resources Inc.
Consolidated Statements of Operations
Unaudited
			Three Months Ended				Nine Months Ended
			September 30,				September 30,
(in thousands, except per share amounts)				2015		2014		2015		2014
Operating revenues:
	Oil sales		$	391,963	$	575,611	$	1,212,437	$	1,696,240
	Natural gas sales			71,511		124,652		201,984		369,684
		Total operating revenues		463,474		700,263		1,414,421		2,065,924
Operating costs and expenses:
	Oil and natural gas production			138,125		140,725		405,925		402,593
	Exploration and abandonments			14,791		16,982		32,566		70,645
	Depreciation, depletion and amortization			329,467		256,765		901,474		715,602
	Accretion of discount on asset retirement obligations			1,853		1,769		5,894		5,162
	Impairments of long-lived assets			7,588		15,476		7,588		15,476
	General and administrative (including non-cash stock-based compensation of
		$16,327 and $13,465 for the three months ended September 30, 2015
		and 2014, respectively, and $47,272 and $34,672 for the nine months
		ended September 30, 2015 and 2014, respectively)		60,052		52,763		179,776		150,048
	Gain on derivatives			(413,130)		(326,229)		(381,071)		(125,907)
		Total operating costs and expenses		138,746		158,251		1,152,152		1,233,619
Income from operations				324,728		542,012		262,269		832,305
Other income (expense):
	Interest expense			(53,752)		(52,601)		(160,803)		(164,124)
	Loss on extinguishment of debt			-		-		-		(4,316)
	Other, net			556		2,155		(9,463)		(6,833)
		Total other expense		(53,196)		(50,446)		(170,266)		(175,273)
Income before income taxes				271,532		491,566		92,003		657,032
	Income tax expense			(91,873)		(186,363)		(25,315)		(248,753)
Net income			$	179,659	$	305,203	$	66,688	$	408,279
Earnings per share:
	Basic net income		$	1.49	$	2.70	$	0.56	$	3.74
	Diluted net income		$	1.49	$	2.69	$	0.56	$	3.73
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 Issued				Paid-in		Retained	Treasury Stock			Stockholders’
(in thousands)			Shares		Amount		Capital		Earnings	Shares		Amount		Equity
BALANCE AT DECEMBER 31, 2014			113,265	$	113	$	3,027,412	$	2,279,741	260	$	(26,478)	$	5,280,788
	Net income		-		-		-		66,688	-		-		66,688
	Issuance of common stock		6,900		7		741,502		-	-		-		741,509
	Stock options exercised		5		1		58		-	-		-		59
	Grants of restricted stock		450		-		-		-	-		-		-
	Cancellation of restricted stock		(26)		-		-		-	-		-		-
	Stock-based compensation		-		-		47,272		-	-		-		47,272
	Excess tax benefits related to stock-based
		compensation	-		-		2,429		-	-		-		2,429
	Purchase of treasury stock		-		-		-		-	44		(4,963)		(4,963)
BALANCE AT SEPTEMBER 30, 2015			120,594	$	121	$	3,818,673	$	2,346,429	304	$	(31,441)	$	6,133,782
The accompanying notes are an integral part of these consolidated financial statements.

3

Concho Resources Inc.
Consolidated Statements of Cash Flows
Unaudited
					Nine Months Ended
					September 30,
(in thousands)					2015		2014
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income				$	66,688	$	408,279
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization				901,474		715,602
		Accretion of discount on asset retirement obligations				5,894		5,162
		Impairments of long-lived assets				7,588		15,476
		Exploration and abandonments, including dry holes				25,859		56,626
		Non-cash stock-based compensation expense				47,272		34,672
		Deferred income taxes				6,565		219,502
		Loss on disposition of assets and other				1,588		8,697
		Gain on derivatives				(381,071)		(125,907)
		Other non-cash items				8,074		11,207
	Changes in operating assets and liabilities, net of acquisitions and dispositions:
			Accounts receivable			111,475		(75,963)
			Prepaid costs and other			(3,049)		(19,317)
			Inventory			(7,236)		3,058
			Accounts payable			4,089		18,500
			Revenue payable			(52,366)		13,176
			Other current liabilities			17,749		(234)
				Net cash provided by operating activities		760,593		1,288,536
CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures on oil and natural gas properties					(2,177,144)		(1,754,835)
	Additions to property, equipment and other assets					(45,231)		(25,267)
	Proceeds from the disposition of assets					106		1,122
	Contribution to equity method investment					(45,000)		(30,050)
	Settlements received from (paid on) derivatives					443,441		(26,174)
				Net cash used in investing activities		(1,823,828)		(1,835,204)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from issuance of debt					1,337,900		1,578,000
	Payments of debt					(1,030,900)		(1,828,000)
	Exercise of stock options					59		4,660
	Excess tax benefit from stock-based compensation					2,429		12,049
	Net proceeds from issuance of common stock					741,509		931,989
	Payments for loan costs					-		(10,649)
	Purchase of treasury stock					(4,963)		(5,820)
	Increase (decrease) in bank overdrafts					17,200		(36,718)
				Net cash provided by financing activities		1,063,234		645,511
				Net increase (decrease) in cash and cash equivalents		(1)		98,843
Cash and cash equivalents at beginning of period						21		21
Cash and cash equivalents at end of period					$	20	$	98,864
The accompanying notes are an integral part of these consolidated financial statements.

4

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Note 1. Organization and nature of operations

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

Note 2. Summary of significant accounting policies

Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The Company consolidates the financial statements of these entities. All material intercompany balances and transactions have been eliminated.

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

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, 2014 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 consolidated financial statements. All such adjustments are of a normal, recurring nature. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed in or omitted from these consolidated financial statements. Accordingly, these condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

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 $61.0 million and $68.4 million, net of accumulated amortization of $67.1 million and $59.7 million, at September 30, 2015 and December 31, 2014, respectively.

Equity method investment. The Company owns a 50 percent member interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), to construct a crude oil gathering and transportation system in the northern Delaware Basin. The Company has the option to purchase the member interest of the other investor in ACC. This purchase option becomes exercisable three months after the completion date of the pipeline and remains exercisable for a period of twelve months. The Company accounts for its investment in ACC under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment in ACC is $74.4 million at September 30, 2015 and is included in other assets in the Company’s consolidated balance sheet. The equity loss for the nine months ended September 30, 2015 is approximately $2.7 million and is included in other expense in the Company’s consolidated statement of operations. During the nine months ended September 30, 2015, the Company recorded $2.5 million of capitalized interest on its investment in ACC.

5

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Revenue recognition. Oil and natural gas revenues are recorded at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. The Company follows the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.

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 $5.6 million and $6.1 million for the three months ended September 30, 2015 and 2014, respectively, and $18.4 million and $17.1 million for the nine months ended September 30, 2015 and 2014, respectively.

Recent accounting pronouncements. In April 2015, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Interest–Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires that debt issuance costs related to a recognized debt liability be presented as a direct deduction from the carrying amount of that debt liability. The Company currently presents debt issuance costs on the balance sheet as an asset.

An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted. The Company plans to early adopt this ASU on December 31, 2015. As of September 30, 2015, the Company had $44.2 million of debt issuance costs, which under this standard would be reclassified from an asset to a direct deduction to the related debt liability.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company is evaluating the impact that this new guidance will have on its consolidated financial statements.

Note 3. 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. After an exploratory well has been completed and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural reserves can be classified as proved. In those circumstances, the Company continues to capitalize the well or project costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.The capitalized exploratory well costs are carried in unproved oil and natural gas properties. See Note 16 for the proved and unproved components of oil and natural gas properties. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments expense in the consolidated statements of operations.

6

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

The following table reflects the Company’s net capitalized exploratory well activity during the nine months ended September 30, 2015:

		Nine Months Ended
(in thousands)		September 30, 2015
Beginning capitalized exploratory well costs		$	241,657
	Additions to exploratory well costs pending the determination of proved reserves		113,069
	Reclassifications due to determination of proved reserves		(227,390)
	Exploratory well costs charged to expense		(559)
Ending capitalized exploratory well costs		$	126,777

The following table provides an aging at September 30, 2015 and December 31, 2014 of capitalized exploratory well costs based on the date drilling was completed:

			September 30,		December 31,
(dollars in thousands)			2015		2014
Capitalized exploratory well costs that have been capitalized for a period of one year or less		$	117,045	$	232,346
Capitalized exploratory well costs that have been capitalized for a period greater than one year			9,732		9,311
	Total capitalized exploratory well costs	$	126,777	$	241,657
Number of projects with exploratory well costs that have been capitalized for a period greater
	than one year		5		7

Delaware Basin project. At September 30, 2015, the Company had approximately $5.6 million of suspended well costs greater than one year recorded for a well that was initially drilled to monitor nearby wells but is now undergoing tests to determine its commercial production capability.

Projects operated by others. At September 30, 2015, the Company had approximately $4.1 million of suspended well costs greater than one year recorded for four wells that are operated by others and waiting on completion.

7

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Note 4. Asset retirement obligations

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and facilities. The following table summarizes the Company’s asset retirement obligation activity during the nine months ended September 30, 2015:

		Nine Months Ended
(in thousands)		September 30, 2015
Asset retirement obligations, beginning of period		$	119,881
	Liabilities incurred from new wells		3,534
	Liabilities assumed in acquisitions		2,030
	Accretion expense		5,894
	Liabilities settled upon plugging and abandoning wells		(4,684)
	Revision of estimates		(11,286)
Asset retirement obligations, end of period		$	115,369

Note 5.Stock incentive plan

The Company’s 2015 Stock Incentive Plan provides for granting stock options, restricted stock awards and performance awards to directors, officers and employees of the Company.

A summary of the Company’s activity for the nine months ended September 30, 2015 is presented below:

		Restricted		Stock		Performance
		Stock		Options		Units
Outstanding at December 31, 2014			1,091,309		47,713		250,314
	Awards granted (a)		450,356		-		176,330
	Options exercised		-		(4,812)		-
	Awards cancelled / forfeited		(25,903)		-		-
	Lapse of restrictions		(298,884)		-		-
Outstanding at September 30, 2015		1,216,878		42,901		426,644
(a) Weighted average grant date fair value per share		$	109.74	$	-	$	156.86

8

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at September 30, 2015:

(in thousands)
Remaining 2015		$	15,991
2016			47,718
2017			27,388
2018			6,448
2019			273
Thereafter			4
	Total	$	97,822

Note 6. 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, collars and floors, 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, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

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). 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.

9

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Financial Assets and Liabilities Measured at Fair Value

The following table presents the carrying amounts and fair values of the Company’s financial instruments at September 30, 2015 and December 31, 2014:

			September 30, 2015				December 31, 2014
			Carrying		Fair		Carrying		Fair
(in thousands)			Value		Value		Value		Value
	Assets:
		Derivative instruments	$	690,330	$	690,330	$	752,700	$	752,700
	Liabilities:
		Credit facility	$	446,500	$	415,919	$	139,500	$	131,068
		7.0% senior notes due 2021	$	600,000	$	612,000	$	600,000	$	625,500
		6.5% senior notes due 2022	$	600,000	$	592,500	$	600,000	$	628,500
		5.5% senior notes due 2022	$	600,000	$	568,500	$	600,000	$	598,500
		5.5% senior notes due 2023	$	1,575,774	$	1,500,925	$	1,577,820	$	1,573,875

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

Credit facility. The fair value of the Company’s credit facility is estimated by discounting the principal and interest payments at the Company’s credit-adjusted discount rate at the reporting date, which utilizes inputs that are Level 2 measurements in the fair value hierarchy.

Senior notes. The fair values of the Company’s senior notes are based on quoted market prices. The debt securities are not actively traded and, therefore, are classified as Level 2 in the fair value hierarchy.

10

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification,even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at September 30, 2015 and December 31, 2014. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.

September 30, 2015
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable				Consolidated		Consolidated
				Assets				Inputs		Inputs		Total		Balance		Balance
(in thousands)				(Level 1)				(Level 2)		(Level 3)		Fair Value		Sheet		Sheet
	Assets:
		Current:
			Commodity derivatives		$	-	$	617,634	$	-	$	617,634	$	(36,198)	$	581,436
		Noncurrent:
			Commodity derivatives			-		123,867		-		123,867		(14,973)		108,894
	Liabilities:
		Current:
			Commodity derivatives			-		(36,198)		-		(36,198)		36,198		-
		Noncurrent:
			Commodity derivatives			-		(14,973)		-		(14,973)		14,973		-
	Net derivative instruments				$	-	$	690,330	$	-	$	690,330	$	-	$	690,330

11

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

December 31, 2014
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable				Consolidated		Consolidated
				Assets				Inputs		Inputs		Total		Balance		Balance
(in thousands)				(Level 1)				(Level 2)		(Level 3)		Fair Value		Sheet		Sheet
	Assets:
		Current:
			Commodity derivatives		$	-	$	501,717	$	-	$	501,717	$	(11,366)	$	490,351
		Noncurrent:
			Commodity derivatives			-		262,349		-		262,349		-		262,349
	Liabilities:
		Current:
			Commodity derivatives			-		(11,366)		-		(11,366)		11,366		-
		Noncurrent:
			Commodity derivatives			-		-		-		-		-		-
	Net derivative instruments				$	-	$	752,700	$	-	$	752,700	$	-	$	752,700

Concentrations of credit risk.At September 30, 2015, the Company’s primary concentration of credit risks are the risk of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations.

The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 7 for additional information regarding the Company’s derivative activities.

12

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

Impairments of long-lived assets. The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by depletion base or by individual well for those wells not constituting part of a depletion base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value of the properties would be recognized at that time.

The Company calculates the estimated fair values of its long-lived assets using a discounted future cash flow model. Management’s assumptions associated with the calculation of discounted future cash flows include (i) market estimates of commodity prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated reserves, and (vii) prevailing market rates of other sources of income and costs. These are classified as Level 3 fair value assumptions.

As a result of management’s assessments, the Company recognized impairment charges to reduce the carrying values to their fair values. The following table reports the carrying amount, estimated fair value and impairment expense of long-lived assets for the indicated periods:

				Estimated
		Carrying		Fair Value		Impairment
(in thousands)		Amount		(Level 3)		Expense
September 2015	$	18,023	$	10,435	$	7,588
September 2014	$	26,790	$	11,314	$	15,476

It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) commodity futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) results of future drilling activities and (v) changes in market rates for facilities income and expenses.

Based on the factors above as of September 30, 2015, the Company determined that undiscounted future cash flows attributable to a certain depletion group indicated that the carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows further decline.

13

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Note 7. Derivative financial instruments

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

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

The following table summarizes the gains (losses) reported in earnings related to the commodity derivative instruments for the three and nine months ended September 30, 2015 and 2014:

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
(in thousands)				2015		2014		2015		2014
Gain (loss) on derivatives:
	Oil derivatives		$	404,012	$	316,559	$	367,743	$	128,684
	Natural gas derivatives			9,118		9,670		13,328		(2,777)
		Total	$	413,130	$	326,229	$	381,071	$	125,907
The following table represents the Company’s cash receipts from (payments on) derivatives for the three and nine months ended September 30, 2015 and 2014:
			Three Months Ended				Nine Months Ended
			September 30,				September 30,
(in thousands)				2015		2014		2015		2014
Cash receipts from (payments on) derivatives:
	Oil derivatives		$	155,732	$	14,271	$	419,047	$	(20,067)
	Natural gas derivatives			8,301		446		24,394		(6,107)
		Total	$	164,033	$	14,717	$	443,441	$	(26,174)

14

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Commodity derivative contracts at September 30, 2015. The following table sets forth the Company’s outstanding derivative contracts at September 30, 2015. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at September 30, 2015 are expected to settle by June 30, 2017.

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2015:
		Volume (Bbl)								5,924,000		5,924,000
		Price per Bbl							$	73.68	$	73.68
	2016:
		Volume (Bbl)		5,513,000		4,983,000		4,743,000		4,320,000		19,559,000
		Price per Bbl	$	76.74	$	78.02	$	77.81	$	60.84	$	73.81
	2017:
		Volume (Bbl)		3,929,000		3,799,000		-		-		7,728,000
		Price per Bbl	$	62.43	$	62.72	$	-	$	-	$	62.57
Oil Basis Swaps: (b)
	2015:
		Volume (Bbl)								5,428,000		5,428,000
		Price per Bbl							$	(2.41)	$	(2.41)
	2016:
		Volume (Bbl)		4,761,000		4,458,000		4,232,000		3,772,000		17,223,000
		Price per Bbl	$	(1.75)	$	(1.78)	$	(1.75)	$	(1.81)	$	(1.77)
	2017:
		Volume (Bbl)		3,330,000		3,367,000		-		-		6,697,000
		Price per Bbl	$	(1.42)	$	(1.42)	$	-	$	-	$	(1.42)
Natural Gas Swaps: (c)
	2015:
		Volume (MMBtu)								5,980,000		5,980,000
		Price per MMBtu							$	4.16	$	4.16
	2016:
		Volume (MMBtu)		5,460,000		5,460,000		5,520,000		5,520,000		21,960,000
		Price per MMBtu	$	3.10	$	3.10	$	3.10	$	3.10	$	3.10
Natural Gas Basis Swaps: (d)
	2015:
		Volume (MMBtu)								1,380,000		1,380,000
		Price per MMBtu							$	(0.13)	$	(0.13)
(a) The index prices for the oil price swaps are based on the New York Mercantile Exchange (“NYMEX”) – West Texas Intermediate
	(“WTI”) monthly average futures price.
(b) The basis differential price is between Midland – WTI and Cushing – WTI.
(c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.
(d) The basis differential price is between the El Paso Permian delivery point and NYMEX – Henry Hub delivery point.

Derivative counterparties.  The Company uses credit and other financial criteria to evaluate the creditworthiness of counterparties to its derivative instruments. The Company believes that all of its derivative counterparties are currently acceptable credit risks. Other than provided by the Company’s revolving credit facility, the Company is not required to provide credit support or collateral to any counterparties under its derivative contracts, nor are they required to provide credit support to the Company.

15

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

At September 30, 2015, the Company had a net asset position of $690.3 million as a result of outstanding derivative contracts which are reflected in the accompanying consolidated balance sheets. The Company assessed this balance for concentration risk and noted balances of approximately $93.9 million, $91.0 million, $78.9 million and $67.1 million with Barclays Bank PLC,J.P. Morgan Chase Bank, Wells Fargo Bank, N.A. and KeyBank National Association, respectively.

Note 8. Debt 

The Company’s debt consisted of the following at September 30, 2015 and December 31, 2014:

				September 30,		December 31,
(in thousands)				2015		2014
Credit facility			$	446,500	$	139,500
7.0% unsecured senior notes due 2021				600,000		600,000
6.5% unsecured senior notes due 2022				600,000		600,000
5.5% unsecured senior notes due 2022				600,000		600,000
5.5% unsecured senior notes due 2023				1,550,000		1,550,000
Unamortized original issue premium				25,774		27,820
	Less: current portion			-		-
		Total long-term debt	$	3,822,274	$	3,517,320

Credit facility. The Company’s credit facility, as amended and restated, has a maturity date of May 9, 2019. In April 2015, the Company amended its credit agreement to remove the current ratio financial covenant. The Company’s borrowing base is $3.25 billion until the next scheduled borrowing base redetermination in May 2016. At September 30, 2015, commitments from the Company’s bank group totaled $2.5 billion.

Senior notes. Interest on the Company’s senior notes is paid in arrears semi-annually. The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by all subsidiaries of the Company, subject to customary release provisions as described in Note 14.

At September 30, 2015, the Company was in compliance with the covenants under all of its debt instruments.

Principal maturities of long-term debt.Principal maturities of long-term debt outstanding at September 30, 2015 were as follows:

(in thousands)
Remaining 2015		$	-
2016			-
2017			-
2018			-
2019			446,500
2020			-
Thereafter			3,350,000
	Total	$	3,796,500

16

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Interest expense.  The following amounts have been incurred and charged to interest expense for the three and nine months ended September 30, 2015 and 2014:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
(in thousands)			2015		2014		2015		2014
Cash payments for interest		$	43,952	$	42,417	$	149,184	$	152,217
Amortization of original issue premium			(692)		(654)		(2,046)		(1,936)
Amortization of deferred loan origination costs			2,502		2,423		7,447		8,495
Net changes in accruals			9,427		9,312		10,044		6,245
	Interest costs incurred		55,189		53,498		164,629		165,021
Less: capitalized interest			(1,437)		(897)		(3,826)		(897)
	Total interest expense	$	53,752	$	52,601	$	160,803	$	164,124

Note 9. Commitments and contingencies

Severance agreements.The Company has entered into severance and change in control agreements with all of its officers. The current annual salaries for the Company’s officers covered under such agreements total approximately $7.9 million.

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

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

Severance tax, royalty and joint interest audits.  The Company is subject to routine severance, royalty and joint interest audits from regulatory bodies and non-operators and makes accruals as necessary for estimated exposure when deemed probable and estimable. Additionally, the Company is subject to various possible contingencies that arise primarily from interpretations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, allowable costs under joint interest arrangements and other matters. At September 30, 2015 and December 31, 2014, the Company had $11.9 million and $12.3 million, respectively, accrued for estimated exposure. Although the Company believes that it has estimated its exposure with respect to the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. 

17

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including daywork drilling contracts, water commitment agreements, throughput volume delivery commitments and power commitments. The following table summarizes the Company’s commitments at September 30, 2015:

(in thousands)
Remaining 2015		$	16,694
2016			39,948
2017			25,578
2018			22,136
2019			13,591
2020			7,368
Thereafter			46,165
	Total	$	171,480

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, 2015 and 2014 were approximately $2.0 million and $1.9 million, respectively, and approximately $5.9 million and $5.3 million for the nine months ended September 30, 2015 and 2014, respectively.

Future minimum lease commitments under non-cancellable operating leases at September 30, 2015 were as follows:

(in thousands)
Remaining 2015		$	2,049
2016			7,480
2017			7,573
2018			6,784
2019			5,427
2020			4,733
Thereafter			5,090
	Total	$	39,136

Note 10. Income taxes

The effective income tax rates were 33.8 percent and 37.9 percent for the three months ended September 30, 2015 and 2014, respectively, and 27.5 percent and 37.9 percent for the nine months ended September 30, 2015 and 2014, respectively. Total income tax expense for the three and nine months ended September 30, 2015 and 2014 differed from amounts computed by applying the United States federal statutory tax rates to pre-tax earnings due primarily to state taxes and the impact of permanent differences between book and taxable income.

18

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Note 11. Related party transactions

The following table summarizes charges incurred with and payments made to related parties and reported in the Company’s consolidated statements of operations for the periods presented:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)		2015		2014		2015		2014
Amounts paid to a partnership in which a director has an ownership interest (a)	$	1,418	$	4,955	$	4,515	$	11,010
Amounts paid to a director and certain officers of the Company (b)	$	20	$	48	$	575	$	205

(a)   Amounts include royalties on certain properties and lease bonus payments paid to a partnership in which a director of the Company is the general partner and owns a 3.5 percent partnership interest.

(b)   Amounts include revenue interests, overriding royalty interests and net profits interests in properties owned by the Company made to a director and certain officers (or affiliated entities). Amounts also include payments for an acreage acquisition and lease bonuses to an affiliated entity of an officer.

19

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Note 12. Net income per share

The Company uses the two-class method of calculating net income per share because certain of the Company’s unvested share-based awards qualify as participating securities.

The following table reconciles the Company’s income from operations and income attributable to common stockholders to the basic and diluted earnings used to determine the Company’s income per share amounts for the three and nine months ended September 30, 2015 and 2014, respectively, under the two-class method:

			Three Months Ended				Nine Months Ended
		September 30,				September 30,
(in thousands, except per share amounts)		2015		2014		2015		2014
Income as reported		$	179,659	$	305,203	$	66,688	$	408,279
Participating basic earnings			(1,850)		(3,557)		(648)		(4,687)
	Basic income attributable to common stockholders		177,809		301,646		66,040		403,592
Reallocation of participating earnings			5		10		3		15
	Diluted income attributable to common stockholders	$	177,814	$	301,656	$	66,043	$	403,607
Income per common share:
	Basic	$	1.49	$	2.70	$	0.56	$	3.74
	Diluted	$	1.49	$	2.69	$	0.56	$	3.73

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and nine months ended September 30, 2015 and 2014:

		Three Months Ended		Nine Months Ended
		September 30,		September 30,
(in thousands)		2015	2014	2015	2014
Weighted average common shares outstanding:
	Basic	119,058	111,680	117,363	107,816
	Dilutive common stock options	24	75	25	102
	Dilutive performance units	333	244	433	230
	Diluted	119,415	111,999	117,821	108,148

Performance unit awards. The number of shares of common stock that will ultimately be issued for performance units will be determined by a combination of (i) comparing the Company’s total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. The performance period is 36 months. The actual payout of shares will be between zero and 300 percent of the performance units granted depending on the Company’s performance at the end of the performance period.

20

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Note 13. Stockholders’ equity

Public common stock offering. In March 2015, the Company issued 6.9 million shares of its common stock in a public offering at $107.49 per share and received net proceeds of approximately $741.5 million.

Note 14. Subsidiary guarantors

All of the Company’s 100 percent owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be releasedin certain customary circumstances, including (i) in connection with any sale, exchange or other disposition, whether by merger, consolidation or otherwise, of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Company to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee.

See Note 8 for a summary of the Company’s senior notes. In accordance with practices accepted by the United States Securities and Exchange Commission, the Company has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors.

The following condensed consolidating balance sheets at September 30, 2015 and December 31, 2014, condensed consolidating statements of operations for the three and nine months ended September 30, 2015 and 2014 and condensed consolidating statements of cash flows for the nine months ended September 30, 2015 and 2014, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors are not restricted from making distributions to the Company.

21

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Condensed Consolidating Balance Sheet
September 30, 2015
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
ASSETS
Accounts receivable - related parties		$	8,023,205	$	1,157,041	$	(9,180,246)	$	-
Other current assets			648,121		422,560		-		1,070,681
Oil and natural gas properties, net			-		11,001,693		-		11,001,693
Property and equipment, net			-		160,582		-		160,582
Investment in subsidiaries			3,958,796		-		(3,958,796)		-
Other long-term assets			169,888		124,718		-		294,606
	Total assets	$	12,800,010	$	12,866,594	$	(13,139,042)	$	12,527,562
LIABILITIES AND EQUITY
Accounts payable - related parties		$	1,157,041	$	8,023,205	$	(9,180,246)	$	-
Other current liabilities			277,229		751,425		-		1,028,654
Long-term debt			3,822,274		-		-		3,822,274
Other long-term liabilities			1,409,684		133,168		-		1,542,852
Equity			6,133,782		3,958,796		(3,958,796)		6,133,782
	Total liabilities and equity	$	12,800,010	$	12,866,594	$	(13,139,042)	$	12,527,562

Condensed Consolidating Balance Sheet
December 31, 2014
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
ASSETS
Accounts receivable - related parties		$	6,670,744	$	1,201,950	$	(7,872,694)	$	-
Other current assets			569,545		618,851		-		1,188,396
Oil and natural gas properties, net			-		10,076,878		-		10,076,878
Property and equipment, net			-		129,136		-		129,136
Investment in subsidiaries			4,085,045		-		(4,085,045)		-
Other long-term assets			330,792		74,761		-		405,553
	Total assets	$	11,656,126	$	12,101,576	$	(11,957,739)	$	11,799,963
LIABILITIES AND EQUITY
Accounts payable - related parties		$	1,201,950	$	6,670,744	$	(7,872,694)	$	-
Other current liabilities			217,884		1,209,309		-		1,427,193
Long-term debt			3,517,320		-		-		3,517,320
Other long-term liabilities			1,438,184		136,478		-		1,574,662
Equity			5,280,788		4,085,045		(4,085,045)		5,280,788
	Total liabilities and equity	$	11,656,126	$	12,101,576	$	(11,957,739)	$	11,799,963

22

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2015
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	463,474	$	-	$	463,474
Total operating costs and expenses			412,490		(551,236)		-		(138,746)
	Income (loss) from operations		412,490		(87,762)		-		324,728
Interest expense			(53,752)		-		-		(53,752)
Other, net			(87,206)		556		87,206		556
	Income (loss) before income taxes		271,532		(87,206)		87,206		271,532
Income tax expense			(91,873)		-		-		(91,873)
	Net income (loss)	$	179,659	$	(87,206)	$	87,206	$	179,659

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2014
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	700,263	$	-	$	700,263
Total operating costs and expenses			325,637		(483,888)		-		(158,251)
	Income from operations		325,637		216,375		-		542,012
Interest expense			(52,601)		-		-		(52,601)
Other, net			218,530		2,155		(218,530)		2,155
	Income before income taxes		491,566		218,530		(218,530)		491,566
Income tax expense			(186,363)		-		-		(186,363)
	Net income	$	305,203	$	218,530	$	(218,530)	$	305,203

23

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2015
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	1,414,421	$	-	$	1,414,421
Total operating costs and expenses			379,055		(1,531,207)		-		(1,152,152)
	Income (loss) from operations		379,055		(116,786)		-		262,269
Interest expense			(160,803)		-		-		(160,803)
Other, net			(126,249)		(9,463)		126,249		(9,463)
	Income (loss) before income taxes		92,003		(126,249)		126,249		92,003
Income tax expense			(25,315)		-		-		(25,315)
	Net income (loss)	$	66,688	$	(126,249)	$	126,249	$	66,688

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2014
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	2,065,924	$	-	$	2,065,924
Total operating costs and expenses			124,158		(1,357,777)		-		(1,233,619)
	Income from operations		124,158		708,147		-		832,305
Interest expense			(164,124)		-		-		(164,124)
Loss on extinguishment of debt			(4,316)		-		-		(4,316)
Other, net			701,314		(6,833)		(701,314)		(6,833)
	Income before income taxes		657,032		701,314		(701,314)		657,032
Income tax expense			(248,753)		-		-		(248,753)
	Net income	$	408,279	$	701,314	$	(701,314)	$	408,279

24

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2015
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Net cash flows provided by (used in) operating activities		$	(1,489,475)	$	2,250,068	$	-	$	760,593
Net cash flows provided by (used in) investing activities			443,441		(2,267,269)		-		(1,823,828)
Net cash flows provided by financing activities			1,046,034		17,200		-		1,063,234
	Net decrease in cash and cash equivalents		-		(1)		-		(1)
	Cash and cash equivalents at beginning of period		-		21		-		21
	Cash and cash equivalents at end of period	$	-	$	20	$	-	$	20

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2014
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Net cash flows provided by (used in) operating activities		$	(656,055)	$	1,944,591	$	-	$	1,288,536
Net cash flows used in investing activities			(26,174)		(1,809,030)		-		(1,835,204)
Net cash flows provided by (used in) financing activities			682,229		(36,718)		-		645,511
	Net increase in cash and cash equivalents		-		98,843		-		98,843
	Cash and cash equivalents at beginning of period		-		21		-		21
	Cash and cash equivalents at end of period	$	-	$	98,864	$	-	$	98,864

25

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Note 15. Subsequent events

Public common stock offering. In October 2015, the Company issued approximately 8.9 million shares of its common stock in a public offering at $92.50 per share and received net proceeds of approximately $794.1 million.

New commodity derivative contracts.After September 30, 2015, the Company entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts of the Company’s estimated future production:

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2015:
		Volume (Bbl)								200,000		200,000
		Price per Bbl							$	48.30	$	48.30
	2016:
		Volume (Bbl)		1,209,000		1,002,000		717,000		734,000		3,662,000
		Price per Bbl	$	50.32	$	50.34	$	50.42	$	50.77	$	50.43
	2017:
		Volume (Bbl)		425,000		319,000		2,655,000		2,655,000		6,054,000
		Price per Bbl	$	53.86	$	53.85	$	55.23	$	55.23	$	55.06
Oil Basis Swaps: (b)
	2016:
		Volume (Bbl)		637,000		637,000		644,000		644,000		2,562,000
		Price per Bbl	$	(0.49)	$	(0.49)	$	(0.49)	$	(0.49)	$	(0.49)
	2017:
		Volume (Bbl)		180,000		182,000		184,000		184,000		730,000
		Price per Bbl	$	(0.55)	$	(0.55)	$	(0.55)	$	(0.55)	$	(0.55)
Natural Gas Swaps: (c)
	2016:
		Volume (MMBtu)		1,820,000		1,820,000		1,840,000		1,840,000		7,320,000
		Price per MMBtu	$	2.79	$	2.79	$	2.79	$	2.79	$	2.79
(a)	The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price.
(b)	The basis differential price is between Midland – WTI and Cushing – WTI.
(c)	The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

26

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2015

Unaudited

Note 16. Supplementary information

Capitalized costs

			September 30,		December 31,
(in thousands)			2015		2014
Oil and natural gas properties:
	Proved		$	14,674,114	$	12,795,970
	Unproved			1,008,685		1,071,861
	Less: accumulated depletion			(4,681,106)		(3,790,953)
		Net capitalized costs for oil and natural gas properties	$	11,001,693	$	10,076,878

Costs incurred for oil and natural gas producing activities

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
(in thousands)		2015		2014		2015		2014
Property acquisition costs:
	Proved	$	56,636	$	37,732	$	58,879	$	60,359
	Unproved		161,921		71,915		195,971		107,985
Exploration			201,737		469,290		973,957		1,136,211
Development			99,490		204,938		622,644		609,780
	Total costs incurred for oil and natural gas properties	$	519,784	$	783,875	$	1,851,451	$	1,914,335

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

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

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

Overview

We are an independent oil and natural gas company engaged in the acquisition, development and exploration of oil and natural gas properties. Our core operations are primarily focused in the Permian Basin of Southeast New Mexico and West Texas. We refer to our three core operating areas as the (i) New Mexico Shelf, where we primarily target the Yeso formation with horizontal and vertical development, (ii) Delaware Basin, where we use horizontal drilling to target the Bone Spring formation (including the Avalon shale and the Bone Spring sands) and the Wolfcamp shale formation and (iii) Texas Permian in the Midland Basin, where we target the Wolfcamp and Spraberry formations with horizontal and vertical development. Oil comprised 58.1 percent of our 637.2 MMBoe of estimated proved reserves at December 31, 2014 and 66.7 percent of our 39.0 MMBoe of production for the nine months ended September 30, 2015. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 92.3 percent of our proved developed producing PV-10 and 79.5 percent of our approximately 7,208 gross wells at December 31, 2014. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and stimulation methods used.

Financial and Operating Performance

Our financial and operating performance for the nine months ended September 30, 2015, as compared to the nine months ended September 30, 2014, included the following highlights:

·Net income was $66.7 million ($0.56per diluted share) for the first nine months of 2015, as compared to $408.3million ($3.73per diluted share) during the nine months ended September 30, 2014. The decrease in net income was primarily due to:

•$651.5 million decrease in oil and natural gas revenues as a result of a 48 percent decrease in commodity price realizations per Boe (excluding the effects of derivative activities), partially offset by a 33percent increase in production;  

•$185.9 million increase in depreciation, depletion and amortization expense, primarily due to increased production associated with new wells that were successfully drilled and completed in 2014 and 2015; and

•$29.8 million increase in general and administrative expense due to an increase in the number of employees and related personnel expenses;

partially offset by:

•$255.2 million increase in the gain on derivatives during the nine months ended September 30, 2015, as compared to the same period in 2014;

•$223.5 million change in our income tax provision due to the decrease in income before income taxes; and

•$38.1 million decrease in exploration and abandonment expense due primarily to a reduction in geological and geophysical expense, exploratory dry hole costs and leasehold abandonments in 2015 as compared to 2014.

28

·Average daily sales volumes increased by 33 percent to 143,020 Boe per day during the first nine months of 2015, as compared to 107,682 Boe per day during the first nine months of 2014. The increase is primarily attributable to our successful drilling and completion efforts during 2014 and 2015.

·Net cash provided by operating activities decreased by approximately $527.9 million to $760.6 million for the first nine months of 2015, as compared to $1,288.5 million in the first nine months of 2014, primarily due to a decrease in oil and natural gas revenues offset partially by positive variances in working capital changes.

·Long-term debt increased by approximately $305.0 million during the first nine months of 2015, which, along with proceeds from our March 2015 equity offering, funded our acquisitions and capital expenditures related to our drilling program.

Commodity Prices

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

·continuing economic uncertainty worldwide;

·political and economic developments in oil and natural gas producing regions, including Africa, South America and the Middle East;

·the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil prices and production controls;

·technological advances affecting energy consumption and energy supply;

·the effect of energy conservation efforts;

·the price and availability of alternative fuels;

·domestic and foreign governmental regulations, including limits on the United States’ ability to export crude oil, and taxation;

·the level of global inventories;

·the proximity, capacity, cost and availability of pipelines and other transportation facilities, as well as the availability of commodity processing and gathering and refining capacity;

·risks related to the concentration of our operations in the Permian Basin of Southeast New Mexico and West Texas and the level of commodity inventory in the Permian Basin;

·the quality of the oil we produce;

·the overall global demand for oil natural gas and natural gas liquids;

·the domestic and foreign supply of oil, natural gas and natural gas liquids; and

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

•the United States economy impact,

•weather conditions, and

•the potential for liquefied natural gas deliveries to and exports from the United States.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Notes 7 and 15 of the Condensed Notes to

29

Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commodity derivative positions at September 30, 2015 and additional derivative contracts entered into subsequent to September 30, 2015, respectively.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, average oil and natural gas prices were significantly lower during the comparable periods of 2015 measured against 2014. The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three and nine months ended September 30, 2015 and 2014, as well as the high and low NYMEX prices for the same periods:

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2015		2014		2015		2014
Average NYMEX prices:
	Oil (Bbl)		$	46.70	$	97.31	$	51.10	$	99.65
	Natural gas (MMBtu)		$	2.73	$	3.95	$	2.76	$	4.41
High and Low NYMEX prices:
	Oil (Bbl):
		High	$	56.96	$	105.34	$	61.43	$	107.26
		Low	$	38.24	$	91.16	$	38.24	$	91.16
	Natural gas (MMBtu):
		High	$	2.93	$	4.46	$	3.23	$	6.15
		Low	$	2.52	$	3.75	$	2.49	$	3.75

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $49.63 and $43.20 per Bbl and $2.54 and $2.03 per MMBtu, respectively, during the period from September 30, 2015 to November 2, 2015. At November 2, 2015, the NYMEX oil price and NYMEX natural gas price were $46.14 per Bbl and $2.26 per MMBtu, respectively.

Our total natural gas revenues are derived from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. In the past, our liquids-rich natural gas stream and the related value of the natural gas liquids included in our natural gas revenues resulted in our realized natural gas price (excluding the effects of derivatives) being greater than the related NYMEX natural gas price. However, during the first nine months of 2015, our realized natural gas price (excluding the effects of derivatives) fell below the related NYMEX natural gas price primarily due to the average Mont Belvieu price for a blended barrel of natural gas liquids decreasing to $16.56 per Bbl during the three months ended September 30, 2015, as compared to $34.69 per Bbl during the three months ended September 30, 2014 and $18.18 per Bbl during the nine months ended September 30, 2015, as compared to $37.37 per Bbl during the nine months ended September 30, 2014.

30

Recent Events

Common stock offerings. In October 2015, we issued approximately 8.9 million shares of our common stock in a public offering at $92.50 per share and received net proceeds of approximately $794.1 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility, which were used in part to finance recent acquisitions, and we plan to use the remaining net proceeds for general corporate purposes, which may include funding potential future acquisitions.

In March 2015, we issued 6.9 million shares of our common stock in a public offering at $107.49 per share and received net proceeds of approximately $741.5 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and the remainder for general corporate purposes.

2016 capital budget.In November 2015, we announced our 2016 base capital budget, excluding acquisitions, of approximately $1.4 billion, with drilling and completion capital accounting for approximately $1.2 billion. Our 2016 capital program is expected to continue focusing on horizontal drilling in the Delaware Basin and Midland Basin. Our 2016 capital budget, based on our current expectations of commodity prices and costs, is expected to be within our cash flows. Our budget could change depending on numerous factors, including commodity prices, leverage metrics and industry conditions.

31

Derivative Financial Instruments

Derivative financial instrument exposure. At September 30, 2015, the fair value of our financial derivatives was a net asset of $690.3million. All of our counterparties to these financial derivatives are parties or affiliates of parties to our credit facility and have their outstanding debt commitments and derivative exposures collateralized pursuant to our credit facility. Under the terms of our financial derivative instruments and their collateralization under our credit facility, we do not have exposure to potential “margin calls” on our financial derivative instruments. We currently have no reason to believe that our counterparties to these commodity derivative contracts are not financially viable. Our credit facility does not allow us to offset amounts we may owe a lender against amounts we may be owed related to our financial instruments with such party or its affiliates.

New commodity derivative contracts. After September 30, 2015, we entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts of our estimated future production:

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2015:
		Volume (Bbl)								200,000		200,000
		Price per Bbl							$	48.30	$	48.30
	2016:
		Volume (Bbl)		1,209,000		1,002,000		717,000		734,000		3,662,000
		Price per Bbl	$	50.32	$	50.34	$	50.42	$	50.77	$	50.43
	2017:
		Volume (Bbl)		425,000		319,000		2,655,000		2,655,000		6,054,000
		Price per Bbl	$	53.86	$	53.85	$	55.23	$	55.23	$	55.06
Oil Basis Swaps: (b)
	2016:
		Volume (Bbl)		637,000		637,000		644,000		644,000		2,562,000
		Price per Bbl	$	(0.49)	$	(0.49)	$	(0.49)	$	(0.49)	$	(0.49)
	2017:
		Volume (Bbl)		180,000		182,000		184,000		184,000		730,000
		Price per Bbl	$	(0.55)	$	(0.55)	$	(0.55)	$	(0.55)	$	(0.55)
Natural Gas Swaps: (c)
	2016:
		Volume (MMBtu)		1,820,000		1,820,000		1,840,000		1,840,000		7,320,000
		Price per MMBtu	$	2.79	$	2.79	$	2.79	$	2.79	$	2.79
(a)	The index prices for the oil price swaps are based on the New York Mercantile Exchange (“NYMEX”) – West Texas
	Intermediate (“WTI”) monthly average futures price.
(b)	The basis differential price is between Midland – WTI and Cushing – WTI.
(c)	The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

32

Results of Operations

The following table sets forth summary information concerning our production and operating data for the three and nine months ended September 30, 2015 and 2014. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

					Three Months Ended				Nine Months Ended
					September 30,				September 30,
					2015		2014		2015		2014
Production and operating data:
	Net production volumes:
		Oil (MBbl)				8,945		6,689		26,042		18,764
		Natural gas (MMcf)				28,746		22,513		78,014		63,798
		Total (MBoe)				13,736		10,441		39,044		29,397
	Average daily production volumes:
		Oil (Bbl)				97,228		72,707		95,392		68,733
		Natural gas (Mcf)				312,457		244,707		285,766		233,692
		Total (Boe)				149,304		113,492		143,020		107,682
	Average prices:
		Oil, without derivatives (Bbl)			$	43.82	$	86.05	$	46.56	$	90.40
		Oil, with derivatives (Bbl) (a)			$	61.23	$	88.19	$	62.65	$	89.33
		Natural gas, without derivatives (Mcf)			$	2.49	$	5.54	$	2.59	$	5.79
		Natural gas, with derivatives (Mcf) (a)			$	2.78	$	5.56	$	2.90	$	5.70
		Total, without derivatives (Boe)			$	33.74	$	67.07	$	36.23	$	70.28
		Total, with derivatives (Boe) (a)			$	45.68	$	68.48	$	47.58	$	69.39
	Operating costs and expenses per Boe:
		Lease operating expenses and workover costs			$	7.23	$	8.26	$	7.38	$	8.17
		Oil and natural gas taxes			$	2.83	$	5.21	$	3.02	$	5.53
		Depreciation, depletion and amortization			$	23.99	$	24.58	$	23.09	$	24.35
		General and administrative			$	4.37	$	5.06	$	4.60	$	5.11
	(a)	Includes the effect of cash receipts from (payments on) derivatives:
					Three Months Ended				Nine Months Ended
					September 30,				September 30,
		(in thousands)			2015		2014		2015		2014
		Cash receipts from (payments on) derivatives:
			Oil derivatives		$	155,732	$	14,271	$	419,047	$	(20,067)
			Natural gas derivatives			8,301		446		24,394		(6,107)
				Total	$	164,033	$	14,717	$	443,441	$	(26,174)
		The presentation of average prices with derivatives is a non-GAAP measure as a result of including the cash receipts from (payments on) commodity derivatives that are presented in our statements of cash flows. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community.

33

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

Oil and natural gas revenues.  Revenue from oil and natural gas operations was$463.5 million for the three months ended September 30, 2015, a decrease of$236.8 million (34 percent) from $700.3 million for the three months ended September 30, 2014. This decrease was primarily due to the decrease in realized oil and natural gas prices, partially offset by increased production due to our successful drilling efforts during 2014 and 2015. Specific factors affecting oil and natural gas revenues include the following:

·total oil production was 8,945 MBbl for the three months ended September 30, 2015, an increase of 2,256 MBbl (34 percent) from 6,689 MBbl for the three months ended September 30, 2014; 

·average realized oil price (excluding the effects of derivative activities) was $43.82 per Bbl during the three months ended September 30, 2015, a decrease of 49 percent from $86.05 per Bbl during the three months ended September 30, 2014. For the three months ended September 30, 2015 and 2014, we realized approximately 93.8 percent and 88.4 percent, respectively, of the average NYMEX oil prices for the respective periods. The basis differential between the location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil has a direct effect on our realized oil price. For the three months ended September 30, 2015 and 2014, the average market basis differential between WTI-Midland and WTI-Cushing was a price benefit of $0.72 per Bbl and reduction of  $(9.96) per Bbl, respectively;

·total natural gas production was 28,746 MMcf for the three months ended September 30, 2015, an increase of 6,233 MMcf (28 percent) from 22,513 MMcf for the three months ended September 30, 2014; and

·average realized natural gas price (excluding the effects of derivative activities) was $2.49 per Mcf during the three months ended September 30, 2015, a decrease of 55 percent from $5.54 per Mcf during the three months ended September 30, 2014. For the three months ended September 30, 2015 and 2014, we realized approximately 91.2 percent and 140.3 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Our total natural gas revenues are derived from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. In the past, our liquids-rich natural gas stream and the related value of the natural gas liquids included in our natural gas revenues resulted in our realized natural gas price (excluding the effects of derivatives) being greater than the related NYMEX natural gas price. However, during the three months ended September 30, 2015, our realized natural gas price (excluding the effects of derivatives) fell below the related NYMEX natural gas price primarily due to the average Mont Belvieu price for a blended barrel of natural gas liquids decreasing to $16.56 per Bbl, as compared to $34.69 per Bbl during the three months ended September 30, 2014.

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Production expenses.  The following table provides the components of our total oil and natural gas production costs for the three months ended September 30, 2015 and 2014:

				Three Months Ended September 30,
				2015				2014
					Per				Per
(in thousands, except per unit amounts)			Amount		Boe		Amount		Boe
Lease operating expenses			$	90,232	$	6.57	$	80,441	$	7.70
Taxes:
	Ad valorem			5,817		0.42		4,867		0.47
	Production			33,043		2.41		49,535		4.74
Workover costs				9,033		0.66		5,882		0.56
		Total oil and natural gas production expenses	$	138,125	$	10.06	$	140,725	$	13.47

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

Lease operating expenses were $90.2 million ($6.57 per Boe) for the three months ended September 30, 2015, which was an increase of $9.8 million (12 percent) from $80.4 million ($7.70 per Boe) for the three months ended September 30, 2014. The increase in lease operating expenses was primarily due to (i) increased production associated with our wells successfully drilled and completed in 2014 and 2015 and (ii) an increase in saltwater disposal system activity. The decrease in lease operating expenses per Boe was primarily due to increased production efficiencies resulting in higher volume wells successfully drilled and completed in the fourth quarter of 2014 and during the nine months ended 2015.

Production taxes per unit of production were $2.41 per Boe during the three months ended September 30, 2015, a decrease of 49 percent from $4.74 per Boe during the three months ended September 30, 2014. The decrease was directly related to the decrease in oil and natural gas prices. Over the same period, our per Boe prices (excluding the effects of derivatives) decreased 50 percent.

Workover expenses were approximately $9.0 million and $5.9 million for the three months ended September 30, 2015 and 2014, respectively. The increase was primarily related to workovers performed on saltwater disposal systems during 2015.

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Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the three months ended September 30, 2015 and 2014:

		Three Months Ended
		September 30,
(in thousands)		2015		2014
Geological and geophysical		$	827	$	2,031
Exploratory dry hole costs			224		10,063
Leasehold abandonments			13,283		4,618
Other			457		270
	Total exploration and abandonments	$	14,791	$	16,982

Our geological and geophysical expense for the periods presented above primarily consists of the costs of acquiring and processing geophysical data and core analysis.

Our exploratory dry hole costs during the three months ended September 30, 2014 were primarily related to expensing unsuccessful wells drilled as part of our extension efforts in our Delaware Basin acreage.

For the three months ended September 30, 2015 and 2014, we recorded approximately $13.3 million and $4.6 million, respectively, of leasehold abandonments. For the three months ended September 30, 2015, our abandonments were primarily related to non-core acreage in our Delaware Basin area.

Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the three months ended September 30, 2015 and 2014:

		Three Months Ended September 30,
		2015				2014
				Per				Per
(in thousands, except per unit amounts)		Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties		$	324,517	$	23.63	$	252,076	$	24.14
Depreciation of other property and equipment			4,585		0.33		4,324		0.41
Amortization of intangible assets - operating rights			365		0.03		365		0.03
	Total depletion, depreciation and amortization	$	329,467	$	23.99	$	256,765	$	24.58
Oil price used to estimate proved oil reserves at period end		$	55.73			$	95.56
Natural gas price used to estimate proved natural gas reserves at period end		$	3.06			$	4.24

Depletion of proved oil and natural gas properties was $324.5 million ($23.63 per Boe) for the three months ended September 30, 2015, an increase of $72.4 million (29 percent) from $252.1 million ($24.14 per Boe) for the three months ended September 30, 2014. The increase in depletion expense was primarily due to increased production associated with new wells that were successfully drilled and completed in 2014 and 2015. The decrease in depletion expense per Boe period over period was primarily due to a reduction in the net book value of our oil and natural gas properties due to a non-cash impairment charge of approximately $431.7 million recorded in the fourth quarter of 2014 and increased proved reserves supported by (i) one or more reliable technologies and (ii) our successful exploratory drilling program, partially offset by lower commodity prices.

The increase in depreciation expense was primarily associated with additional other property and equipment related to buildings and other items as a result of our increased number of employees.

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Impairments of long-lived assets.  We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Due primarily todownward adjustments to the economically recoverable proved reserves associated with decreases in estimated realized oil and natural gas prices, we recognized a non-cash charge against earnings of approximately $7.6 million during the three months ended September 30, 2015, which was primarily attributable to non-core properties in our Texas Permian area, as compared to approximately $15.5 million during the three months ended September 30, 2014, which was primarily attributable to non-core properties in our Delaware Basin area.

Based on economic factors as of September 30, 2015, we determined that undiscounted future cash flows attributable to a certain depletion group with net book value of approximately $1.9 billion indicated that the carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows) since September 30, 2015. We estimate that, if this depletion group was to become impaired in a future period, we could recognize non-cash impairment in that period in excess of $1.0 billion.

General and administrative expenses.The following table provides components of our general and administrative expenses for the three months ended September 30, 2015 and 2014:

		Three Months Ended September 30,
		2015				2014
				Per				Per
(in thousands, except per unit amounts)		Amount		Boe		Amount		Boe
General and administrative expenses		$	49,354	$	3.59	$	45,389	$	4.35
Non-cash stock-based compensation			16,327		1.19		13,465		1.29
Less: Third-party operating fee reimbursements			(5,629)		(0.41)		(6,091)		(0.58)
	Total general and administrative expenses	$	60,052	$	4.37	$	52,763	$	5.06

General and administrative expenses were approximately $60.1 million ($4.37 per Boe) for the three months ended September 30, 2015, an increase of $7.3 million (14 percent) from $52.8 million ($5.06 per Boe) for the three months ended September 30, 2014. The increase in cash general and administrative expenses and non-cash stock-based compensation was primarily due to an increase in the number of employees and related personnel expenses. During the nine months ended September 30, 2015, we began to slow both our activity and hiring rate. The decrease in total general and administrative expenses per Boe was primarily due to increased production from our wells successfully drilled and completed in 2014 and 2015, partially offset by an increase in the number of employees and related personnel expenses in order to manage our activities.

As the operator of certain oil and natural gas properties in which we own an interest, we earn overhead reimbursements during the drilling and production phases of the property. We earned reimbursements of $5.6 million and $6.1 million during the three months ended September 30, 2015 and 2014, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations. The decrease in third-party operating fee reimbursements was primarily due to our decrease in drilling and completion activity during the three months ended September 30, 2015 as compared to the corresponding period in 2014.

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Gain on derivatives.The following table sets forth the gain on derivatives for the three months ended September 30, 2015 and 2014:

			Three Months Ended
			September 30,
(in thousands)				2015		2014
Gain on derivatives:
	Oil derivatives		$	404,012	$	316,559
	Natural gas derivatives			9,118		9,670
		Total	$	413,130	$	326,229
The following table represents our cash receipts from derivatives for the three months ended September 30, 2015 and 2014:
			Three Months Ended
			September 30,
(in thousands)				2015		2014
Cash receipts from derivatives:
	Oil derivatives		$	155,732	$	14,271
	Natural gas derivatives			8,301		446
		Total	$	164,033	$	14,717

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.

Interest expense.  The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the three months ended September 30, 2015 and 2014:

		Three Months Ended
		September 30,
(dollars in thousands)		2015		2014
Interest expense		$	53,752	$	52,601
Capitalized interest			1,437		897
	Interest expense, excluding impact of capitalized interest	$	55,189	$	53,498
Weighted average interest rate - credit facility			2.2%		-
Weighted average interest rate - senior notes			5.9%		5.9%
	Total weighted average interest rate		5.6%		5.9%
Weighted average credit facility balance		$	341,667	$	-
Weighted average senior notes balance			3,350,000		3,350,000
	Total weighted average debt balance	$	3,691,667	$	3,350,000

The increase in the weighted average debt balance for the three months ended September 30, 2015 as compared to the corresponding period in 2014 was due to capital expenditures in excess of our cash flows, primarily related to our drilling

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program and acquisitions, offset in part by cash received from our March 2015 equity offering. The increase in interest expense was due to an overall increase in the weighted average debt balance.

Income tax provisions.  We recorded income tax expense of $91.9 million and $186.4 million for the three months ended September 30, 2015 and 2014, respectively. The effective income tax rates for the three months ended September 30, 2015 and 2014 were 33.8 percent and 37.9 percent, respectively.

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Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

Oil and natural gas revenues.  Revenue from oil and natural gas operations was$1,414.4 million for the nine months ended September 30, 2015, a decrease of$651.5 million (32 percent) from $2,065.9 million for the nine months ended September 30, 2014. This decrease was primarily due to a decrease in realized oil and natural gas prices, offset partially by increased production due to our successful drilling efforts during 2014 and 2015. Specific factors affecting oil and natural gas revenues include the following:

·total oil production was 26,042 MBbl for the nine months ended September 30, 2015, an increase of 7,278 MBbl (39 percent) from 18,764 MBbl for the nine months ended September 30, 2014; 

·average realized oil price (excluding the effects of derivative activities) was $46.56 per Bbl during the nine months ended September 30, 2015, a decrease of 48 percent from $90.40 per Bbl during the nine months ended September 30, 2014. For the nine months ended September 30, 2015 and 2014, we realized approximately 91.1 percent and 90.7 percent, respectively, of the average NYMEX oil prices for the respective periods. The basis differential between the location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil has a direct effect on our realized oil price. For the nine months ended September 30, 2015 and 2014, the market basis differential between WTI-Midland and WTI-Cushing was a price reduction of $(0.62) per Bbl and $(7.28) per Bbl, respectively;

·total natural gas production was 78,014 MMcf for the nine months ended September 30, 2015, an increase of 14,216 MMcf (22 percent) from 63,798 MMcf for the nine months ended September 30, 2014; and

·average realized natural gas price (excluding the effects of derivative activities) was $2.59 per Mcf during the nine months ended September 30, 2015, a decrease of 55 percent from $5.79 per Mcf during the nine months ended September 30, 2014. For the nine months ended September 30, 2015 and 2014, we realized approximately 93.8 percent and 131.3 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Our total natural gas revenues are derived from the value of the natural gas liquids, with the remaining portion coming from the value of the dry natural gas residue. In the past, our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues resulted in our realized natural gas price (excluding the effects of derivatives) being greater than the related NYMEX natural gas price. However, during the nine months ended September 30, 2015, our realized natural gas price (excluding the effects of derivatives) fell below the related NYMEX natural gas price primarily due to the average Mont Belvieu price for a blended barrel of natural gas liquids decreasing to $18.18 per Bbl, as compared to $37.37 per Bbl during the nine months ended September 30, 2014.

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Production expenses.  The following table provides the components of our total oil and natural gas production costs for the nine months ended September 30, 2015 and 2014:

			Nine Months Ended September 30,
			2015				2014
						Per				Per
(in thousands, except per unit amounts)				Amount		Boe		Amount		Boe
Lease operating expenses			$	265,949	$	6.81	$	226,944	$	7.72
Taxes:
	Ad valorem			17,380		0.45		15,946		0.54
	Production			100,466		2.57		146,593		4.99
Workover costs				22,130		0.57		13,110		0.45
		Total oil and natural gas production expenses	$	405,925	$	10.40	$	402,593	$	13.70

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

Lease operating expenses were $265.9 million ($6.81 per Boe) for the nine months ended September 30, 2015, which was an increase of $39.0 million (17 percent) from $226.9 million ($7.72 per Boe) for the nine months ended September 30, 2014. The increase in lease operating expenses was primarily due to (i) increased production associated with our wells successfully drilled and completed in 2014 and 2015 and (ii) an increase in saltwater disposal system activity. The decrease in lease operating expenses per Boe was primarily due to increased production efficiencies resulting in higher volume wells successfully drilled and completed in the fourth quarter of 2014 and during the nine months ended 2015.

Production taxes per unit of production were $2.57 per Boe during the nine months ended September 30, 2015, a decrease of 48 percent from $4.99 per Boe during the nine months ended September 30, 2014. The decrease was directly related to the decrease in oil and natural gas prices. Over the same period, our per Boe prices (excluding the effects of derivatives) decreased 48 percent.

Workover expenses were approximately $22.1 million and $13.1 million for the nine months ended September 30, 2015 and 2014, respectively. The increase was primarily related to workovers performed on saltwater disposal systems during 2015.

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Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the nine months ended September 30, 2015 and 2014:

		Nine Months Ended
		September 30,
(in thousands)		2015		2014
Geological and geophysical		$	4,313	$	13,790
Exploratory dry hole costs			9,213		36,593
Leasehold abandonments			16,646		19,756
Other			2,394		506
	Total exploration and abandonments	$	32,566	$	70,645

Our geological and geophysical expense for the periods presented above primarily consists of the costs of acquiring and processing geophysical data and core analysis. During the nine months ended September 30, 2014, we acquired geological and geophysical data related to our northern Delaware Basin acreage.

Our exploratory dry hole costs during the nine months ended September 30, 2015 were primarily related to (i) an uneconomic well in our Delaware Basin area that was attempting to establish production in a different zone and (ii) expensing an unsuccessful well, which we did not operate, that was located in our New Mexico Shelf area. Our exploratory dry hole costs during the nine months ended September 30, 2014 were primarily related to (i) expensing unsuccessful wells drilled as part of our extension efforts in our Delaware Basin acreage and (ii) an unsuccessful horizontal lateral in the New Mexico Shelf area.

For the nine months ended September 30, 2015 and 2014, we recorded approximately $16.6 million and $19.8 million, respectively, of leasehold abandonments. For the nine months ended September 30, 2015 and 2014, our abandonments were primarily related to non-core acreage in our Delaware Basin 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, 2015 and 2014:

		Nine Months Ended September 30,
		2015				2014
					Per				Per
(in thousands, except per unit amounts)			Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties		$	886,609	$	22.71	$	701,624	$	23.87
Depreciation of other property and equipment			13,769		0.35		12,882		0.44
Amortization of intangible asset - operating rights			1,096		0.03		1,096		0.04
	Total depletion, depreciation and amortization	$	901,474	$	23.09	$	715,602	$	24.35

Depletion of proved oil and natural gas properties was $886.6 million ($22.71 per Boe) for the nine months ended September 30, 2015, an increase of $185.0 million (26 percent) from $701.6 million ($23.87 per Boe) for the nine months ended September 30, 2014. The increase in depletion expense was primarily due to increased production associated with new wells that were successfully drilled and completed in 2014 and 2015. The decrease in depletion expense per Boe period over period was primarily due to a reduction in the net book value of our oil and natural gas properties due to a non-cash impairment charge of approximately $431.7 million recorded in the fourth quarter of 2014 and increased proved reserves supported by (i) one or more reliable technologies and (ii) our successful exploratory drilling program, partially offset by lower commodity prices.

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The increase in depreciation expense was primarily associated with additional other property and equipment related to buildings and other items as a result of our increased number of employees.

Impairments of long-lived assets.  We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Due primarily todownward adjustments to the economically recoverable proved reserves associated with decreases in estimated realized oil and natural gas prices, we recognized a non-cash charge against earnings of approximately $7.6 million during the nine months ended September 30, 2015, which was primarily attributable to non-core properties in our Texas Permian area, as compared to approximately $15.5 million during the nine months ended September 30, 2014, which was primarily attributable to non-core properties in our Delaware Basin area.

Based on economic factors as of September 30, 2015, we determined that undiscounted future cash flows attributable to a certain depletion group with net book value of approximately $1.9 billion indicated that the carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows) since September 30, 2015. We estimate that, if this depletion group was to become impaired in a future period, we could recognize non-cash impairment in that period in excess of $1.0 billion.

General and administrative expenses.The following table provides components of our general and administrative expenses for the nine months ended September 30, 2015 and 2014:

		Nine Months Ended September 30,
		2015				2014
				Per				Per
(in thousands, except per unit amounts)		Amount		Boe		Amount		Boe
General and administrative expenses		$	150,871	$	3.86	$	132,473	$	4.51
Non-cash stock-based compensation			47,272		1.21		34,672		1.18
Less: Third-party operating fee reimbursements			(18,367)		(0.47)		(17,097)		(0.58)
	Total general and administrative expenses	$	179,776	$	4.60	$	150,048	$	5.11

General and administrative expenses were approximately $179.8 million ($4.60 per Boe) for the nine months ended September 30, 2015, an increase of $29.8 million (20 percent) from $150.0 million ($5.11 per Boe) for the nine months ended September 30, 2014. The increase in general and administrative expenses and non-cash stock-based compensation was primarily due to an increase in the number of employees and related personnel expenses. During the nine months ended September 30, 2015, we began to slow both our activity and hiring rate. The decrease in total general and administrative expenses per Boe was primarily due to increased production from our wells successfully drilled and completed in 2014 and 2015, partially offset by an increase in the number of employees and related personnel expenses in order to manage our activities.

As the operator of certain oil and natural gas properties in which we own an interest, we earn overhead reimbursements during the drilling and production phases of the property. We earned reimbursements of $18.4 million and $17.1 million during the nine months ended September 30, 2015 and 2014, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations. The increase in third-party operating fee reimbursements was primarily due to increased reimbursements attributable to more wells operated as a result of continued drilling activity, partially offset by our decreased drilling and completion activity during the third quarter of 2015.

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Gain (loss) on derivatives.The following table sets forth the gain (loss) on derivatives for the nine months ended September 30, 2015 and 2014:

			Nine Months Ended
			September 30,
(in thousands)				2015		2014
Gain (loss) on derivatives:
	Oil derivatives		$	367,743	$	128,684
	Natural gas derivatives			13,328		(2,777)
		Total	$	381,071	$	125,907
The following table represents our cash receipts from (payments on) derivatives for the nine months ended September 30, 2015 and 2014:
			Nine Months Ended
			September 30,
(in thousands)				2015		2014
Cash receipts from (payments on) derivatives:
	Oil derivatives		$	419,047	$	(20,067)
	Natural gas derivatives			24,394		(6,107)
		Total	$	443,441	$	(26,174)

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.

Interest expense.The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the nine months ended September 30, 2015 and 2014:

		Nine Months Ended
		September 30,
(dollars in thousands)		2015		2014
Interest expense		$	160,803	$	164,124
Capitalized interest			3,826		897
	Interest expense, excluding impact of capitalized interest	$	164,629	$	165,021
Weighted average interest rate - credit facility			2.4%		2.3%
Weighted average interest rate - senior notes			5.9%		5.9%
	Total weighted average interest rate		5.7%		5.8%
Weighted average credit facility balance		$	250,505	$	176,245
Weighted average senior notes balance			3,350,000		3,350,000
	Total weighted average debt balance	$	3,600,505	$	3,526,245

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The increase in the weighted average debt balance for the nine months ended September 30, 2015 as compared to the corresponding period in 2014 was due to capital expenditures in excess of our cash flows, primarily related to our drilling program and acquisitions, offset in part by cash received from our March 2015 equity offering.

Loss on extinguishment of debt.In May 2014, we amended and restated our credit facility. We recorded a loss on extinguishment of debt of $4.3 million for the nine months ended September 30, 2014, representing the proportional amount of unamortized deferred loan costs associated with banks with lesser commitments in the amended credit facility syndicate.

Income tax provisions.  We recorded income tax expense of $25.3 million and $248.8 million for the nine months ended September 30, 2015 and 2014, respectively. The effective income tax rates for the nine months ended September 30, 2015 and 2014 were 27.5 percent and 37.9 percent, respectively.

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Capital Commitments, Capital Resources and Liquidity

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

Oil and natural gas properties. Our costs incurred on oil and natural gas properties, excluding acquisitions and asset retirement obligations, during the nine months ended September 30, 2015 and 2014 totaled $1.6 billion and $1.7 billion, respectively. The decrease was primarily due to our reduced drilling and completion activity level during the third quarter of 2015. The primary reason for the differences in the costs incurred and cash flow expenditures was the timing of payments. The 2015 expenditures were funded in part from borrowings under our credit facility and proceeds from our equity offering in March 2015.

2015 capital budget. Our 2015 capital budget is approximately $2.0 billion, excluding the costs of acquisitions other than customary leasehold purchases of acreage. The capital budget will exceed our expected cash flows from operations, and we expect our cash flows from operations, proceeds from our March 2015 and October 2015 equity offerings and borrowings under our credit facility will be sufficient to fund our budgeted capital expenditure needs during 2015.

2016 capital budget.In November 2015, we announced our 2016 base capital budget, excluding acquisitions, of approximately $1.4 billion, with drilling and completion capital accounting for approximately $1.2 billion. Our 2016 capital program is expected to continue focusing on horizontal drilling in the Delaware Basin and Midland Basin. Our 2016 capital budget, based on our current expectations of commodity prices and costs, is expected to be within our cash flows. Our budget could change depending on numerous factors, including commodity prices, leverage metrics and industry conditions.

Acquisitions. The following table reflects our expenditures for acquisitions of proved and unproved properties for the nine months ended September 30, 2015 and 2014:

			Nine Months Ended
			September 30,
(in thousands)			2015		2014
Property acquisition costs:
	Proved		$	58,879	$	60,359
	Unproved (a)			195,971		107,985
		Total property acquisition costs	$	254,850	$	168,344
(a)	Included in the unproved property acquisition costs above are budgeted leasehold acreage acquisitions of $63.1 million and $78.2 million for the nine months ended September 30, 2015 and 2014, respectively.
						��

Contractual obligations.  Our contractual obligations include long-term debt, cash interest expense on debt, operating lease obligations, purchase obligations, employment agreements with executive officers, derivative liabilities, investment contributions related to Alpha Crude Connecter, LLC and other obligations. Since December 31, 2014, the changes in our contractual obligations have not had a material impact on our financial position. See Note 8 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our long-term debt and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for information regarding the interest on our long-term debt and information on changes in the fair value of our open derivative obligations during the nine months ended September 30, 2015.

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

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Capital resources.  Our primary sources of liquidity have been cash flows generated from (i) operating activities and cash settlements received from derivatives, (ii) borrowings under our credit facility and (iii) proceeds from bond and equity offerings. We believe our 2015 expected capital expenditures will exceed our 2015 cash flow, and we have funded the difference with borrowings under our credit facility and proceeds from our equity offering in March 2015 and expect to continue to fund the difference with borrowings under our credit facility and proceeds from our equity offering in October 2015. We believe that we have adequate availability under our credit facility to fund any cash flow deficits.

The following table summarizes our changes in cash and cash equivalents for the nine months ended September 30, 2015 and 2014:

		Nine Months Ended
		September 30,
(in thousands)		2015		2014
Net cash provided by operating activities		$	760,593	$	1,288,536
Net cash used in investing activities			(1,823,828)		(1,835,204)
Net cash provided by financing activities			1,063,234		645,511
	Net increase (decrease) in cash and cash equivalents	$	(1)	$	98,843

Cash flow from operating activities. The decrease in operating cash flows during the nine months ended September 30, 2015 as compared to the same period in 2014 was primarily due to (i) a decrease in oil and natural gas revenues of approximately $651.5 million and (ii) a cash increase in general and administrative expense of approximately $17.1 million, offset in part by approximately $131.5 million of positive variances in operating assets and liabilities.

Our net cash provided by operating activities included an increase of approximately $70.7million and a reduction of approximately $60.8million for the nine months ended September 30, 2015 and 2014, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

Cash flow used in investing activities. During the nine months ended September 30, 2015 and 2014, we invested approximately $2.2 billion and $1.8 billion, respectively, for capital expenditures on oil and natural gas properties. Also, other increases to cash flows used in investing activities during the nine months ended September 30, 2015 as compared to the same period in 2014 included (i) contributions to our equity method investment of $45.0 million during the nine months ended September 30, 2015 compared to $30.1 million during the nine months ended September 30, 2014 and (ii) $45.2 million of investment in other property and equipment during the nine months ended September 30, 2015 compared to $25.3 million during the comparative period of 2014. These increases to cash flow used in investing activities were offset by 2015 settlements received on derivatives of approximately $443.4 million during the nine months ended September 30, 2015 compared to payments of approximately $26.2 million during the nine months ended September 30, 2014.

Cash flow from financing activities.Net cash provided by financing activities was approximately $1,063.2 million and $645.5 million for the nine months ended September 30, 2015 and 2014, respectively. Below is a description of our financing activities:

·In March 2015, we issued shares of our common stock in a public offering and received net proceeds of approximately $741.5 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and the remainder for general corporate purposes.

·During the first nine months of 2015, we had net borrowings on our credit facility of $307.0 million.

·In May 2014, we issued shares of our common stock in a public offering and received net proceeds of approximately $932.0 million during the nine months ended September 30, 2014. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and the remainder for general corporate purposes. 

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·During the first nine months of 2014, we had net payments on our credit facility of $250.0 million.

At September 30, 2015, we had unused commitments of approximately $2.1 billion based on bank commitments of $2.5 billion. The maturity date of the credit facility is May 9, 2019.

Advances on our amended and restated credit facility bear interest, at our option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). The amended and restated credit facility’s interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest margins ranging from 125 to 225 basis points and 25 to 125 basis points, respectively, per annum depending on the utilization of the borrowing base. We pay commitment fees on the unused portion of the available commitment ranging from 30.0 to 37.5 basis points per annum, depending on utilization of the borrowing base. Subject to certain restrictions, with respect to our public debt ratings, the collateral securing the facility may be released.

In conducting our business, we may utilize various financing sources, including the issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock, (iv) common stock and (v) other securities. Over the last three years, we have demonstrated our use of the capital markets by issuing common stock and senior unsecured debt. There are no assurances that we can access the capital markets to obtain additional funding, if needed, and at cost and terms that are favorable to us. We may also sell assets and issue securities in exchange for oil and natural gas assets or interests in energy companies. Additional securities may be of a class senior to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined from time to time by our board of directors. Utilization of some of these financing sources may require approval from the lenders under our credit facility.

Liquidity. Our principal sources of liquidity are cash on hand and available borrowing capacity under our credit facility. At September 30, 2015, we had approximately $20,000of cash on hand.

At September 30, 2015, commitments from our bank group totaled $2.5 billion. In April 2015, we amended our credit agreement to remove the current ratio financial covenant. Our borrowing base is $3.25 billion until our next scheduled borrowing base redetermination in May 2016. There is no assurance that our borrowing base will not be reduced, which could affect our liquidity. Upon a redetermination, our borrowing base could be substantially reduced.

In October 2015, we issued approximately 8.9 million shares of our common stock in a public offering at $92.50 per share and received net proceeds of approximately $794.1 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility, which were used in part to finance recent acquisitions, and we plan to use the remaining net proceeds for general corporate purposes, which may include funding potential future acquisitions.

Debt ratings. We receive debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”), which are subject to regular reviews. S&P’s corporate rating for us is “BB+” with a stable outlook. Moody’s corporate rating for us is “Ba1” with a stable outlook. S&P and Moody’s consider many factors in determining our ratings including: production growth opportunities, liquidity, debt levels and asset and reserve mix. A reduction in our debt ratings could negatively affect our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.

Book capitalization and current ratio.  Our book capitalization at September 30, 2015 was $9.9billion, consisting of debt of $3.8 billion and stockholders’ equity of $6.1 billion. Our debt to book capitalization was 38 percent and 40 percent at September 30, 2015 and December 31, 2014, respectively. Our ratio of current assets to current liabilities was 1.04to 1.0 at September 30, 2015 as compared to 0.83 to 1.0 at December 31, 2014.

Inflation and changes in prices.  Our revenues, the value of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the nine months ended September 30, 2015, we received an average of $46.56per Bbl of oil and $2.59per Mcf of natural gas before consideration of commodity derivative contracts compared to $90.40per Bbl of oil and $5.79per Mcf of natural gas in the nine months ended September 30, 2014. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business.

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Critical Accounting Policies, Practices and Estimates

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

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

There have been no material changes in our critical accounting policies and procedures during the nine months ended September 30, 2015. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the United States Securities and Exchange Commission (the “SEC”) on February 26, 2015.

Recent accounting pronouncements. In April 2015, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Interest–Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires that debt issuance costs related to a recognized debt liability be presented as a direct deduction from the carrying amount of that debt liability. We currently present debt issuance costs on the balance sheet as an asset.

An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted. We plan to early adopt this ASU on December 31, 2015. As of September 30, 2015, we had $44.2 million of debt issuance costs, which under this standard would be reclassified from an asset to a direct deduction to the related debt liability.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements.

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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, 2014.

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, 2015, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit. We do not enter into derivative or other financial instruments for speculative or trading purposes.

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

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

We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set-off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.See Note 7 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative activities.

Commodity price risk. We are exposed to market risk as the prices of our commodities are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of our commodities, we have entered into, and may in the future enter into, additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Our commodity price risk management arrangements are recorded at fair value and thus changes to the future commodity prices will have an impact on net income. The following table sets forth the hypothetical impact on the fair value of the commodity price risk management arrangements from an average increase and decrease in the commodity price of $10.00 per Bbl of oil and $1.00 per MMBtu of natural gas from the commodity prices at September 30, 2015:

				Increase of		Decrease of
				$10 per Bbl and		$10 per Bbl and
(in thousands)				$1 per MMBtu		$1 per MMBtu
Gain (loss):
	Oil derivatives		$	(330,633)	$	330,633
	Natural gas derivatives			(26,320)		26,320
		Total	$	(356,953)	$	356,953

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At September 30, 2015, we had (i) oil price swaps that settle on a monthly basis covering future oil production from October 1, 2015 through June 30, 2017 and (ii) oil basis swaps covering our Midland to Cushing basis differential from October 1, 2015 to June 30, 2017. The average NYMEX oil price for the nine months ended September 30, 2015 was $51.10 per Bbl. At November 2, 2015, the NYMEX oil price was $46.14 per Bbl.

At September 30, 2015, we had (i) natural gas price swaps that settle on a monthly basis covering future natural gas production from October 1, 2015 to December 31, 2016 and (ii) natural gas basis swaps covering our basis differential between the El Paso Permian delivery point and the NYMEX-Henry Hub delivery point from October 1, 2015 to December 31, 2015. The average NYMEX natural gas price for the nine months ended September 30, 2015 was $2.76 per MMBtu. At November 2, 2015, the NYMEX natural gas price was $2.26 per MMBtu.

A decrease in the average forward NYMEX oil and natural gas prices below those at September 30, 2015 would increase the fair value asset of our commodity derivative contracts from their recorded balance at September 30, 2015. Changes in the recorded fair value of our commodity derivative contracts are marked to market through earnings as gains or losses. The potential increase in our fair value asset would be recorded in earnings as a gain. However, an increase in the average forward NYMEX oil and natural gas prices above those at September 30, 2015 would decrease the fair value asset of our commodity derivative contracts from their recorded balance at September 30, 2015. The potential decrease in our fair value asset would be recorded in earnings as a loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.

The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method during the nine months ended September 30, 2015 for 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, 2015:

		Commodity Derivative
		Instruments
(in thousands)		Net Assets (Liabilities) (a)
Fair value of contracts outstanding at December 31, 2014			$	752,700
	Changes in fair values (b)			381,071
	Contract maturities			(443,441)
Fair value of contracts outstanding at September 30, 2015			$	690,330
(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.

See Note 7 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments.

Interest rate risk.Our exposure to changes in interest rates relates primarily to debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. To reduce our exposure to changes in interest rates we may, in the future, enter into 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 borrowing base.

We had total indebtedness of $446.5 million outstanding under our credit facility at September 30, 2015. The impact of a one percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $4.5 million.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at September 30, 2015 at the reasonable assurance level.

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

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PART II – OTHER INFORMATION

Item 1.  Legal Proceedings

We are a party to proceedings and claims incidental to our business. While many of these other matters involve inherent uncertainty, we believe that the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future results of operations. We will continue to evaluate proceedings and claims involving us on a regular basis and will establish and adjust any reserves as appropriate to reflect our assessment of the then current status of the matters.

Item 1A.  Risk Factors

In addition to the risk factor set forth below and the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2014, under the headings “Item 1. Business — Competition,” “— Marketing Arrangements” and “— Applicable Laws and Regulations,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosure About Market Risk,” which risks could materially affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2014 and our Current Reports on Form 8-K other than updating the risk factor below. The risks described in these reports are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. The updated risk factor is as follows:

Risks Related to Our Business

Future price declines could result in a reduction in the carrying value of our proved oil and natural gas properties, which could adversely affect our results of operations.

Declines in commodity prices may result in having to make substantial downward adjustments to the value of our estimated proved reserves. If this occurs, or if our estimates of production or economic factors change, accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our proved oil and natural gas properties for impairments. We are required to perform impairment tests on proved assets whenever events or changes in circumstances warrant a review of our proved oil and natural gas properties. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our oil and natural gas properties, the carrying value may not be recoverable and therefore require a write-down. The primary factors that may affect management’s estimates of future cash flows are (i) commodity future prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves and (iv) results of future drilling activities. We may incur impairment charges in the future, which could materially adversely affect our results of operations in the period incurred.

Additionally, based on the factors above as of September 30, 2015, we determined that undiscounted future cash flows attributable to a certain depletion group with net book value of approximately $1.9 billion indicated that the carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows) since September 30, 2015. We estimate that, if this depletion group was to become impaired in a future period, we could recognize non-cash impairment in that period in excess of $1.0 billion.

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

Period		Total number of shares withheld (a)	Average price per share		Total number of shares purchased as part of publicly announced plans	Maximum number of shares that may yet be purchased under the plan
July 1, 2015 - July 31, 2015		762	$	109.79	-
August 1, 2015 - August 31, 2015		4,326	$	106.67	-
September 1, 2015 - September 30, 2015		146	$	103.06	-
(a)	Represents shares that were withheld by us to satisfy tax withholding obligations of certain of our officers and key employees that arose upon the lapse of restrictions on restricted stock.

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Item 6.  Exhibits

Exhibit  Number	Exhibit
3.1	Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).
3.2	Second Amended and Restated Bylaws of Concho Resources Inc., as amended November 7, 2012 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on November 8, 2012, and incorporated herein by reference).
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).
31.1 (a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 (a)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 (b)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 (b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS (a)	XBRL Instance Document.
101.SCH (a)	XBRL Schema Document.
101.CAL (a)	XBRL Calculation Linkbase Document.
101.DEF (a)	XBRL Definition Linkbase Document.
101.LAB (a)	XBRL Labels Linkbase Document.
101.PRE (a)	XBRL Presentation Linkbase Document.

(a)  Filed herewith.

(b)  Furnished herewith.

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SIGNATURES

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

CONCHO RESOURCES INC.
Date:	November 5, 2015	By	/s/  Timothy A. Leach
			Timothy A. Leach
			Director, Chairman of the Board of Directors, Chief Executive
			Officer and President
			(Principal Executive Officer)
		By	/s/  Darin G. Holderness
			Darin G. Holderness
			Senior Vice President, Chief Financial Officer and Treasurer
			(Principal Financial Officer)
		By	/s/  Brenda R. Schroer
			Brenda R. Schroer
			Vice President and Chief Accounting Officer
			(Principal Accounting Officer)

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EXHIBIT INDEX

Exhibit  Number	Exhibit
3.1	Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).
3.2	Second Amended and Restated Bylaws of Concho Resources Inc., as amended November 7, 2012 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on November 8, 2012, and incorporated herein by reference).
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).
31.1 (a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 (a)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 (b)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 (b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS (a)	XBRL Instance Document.
101.SCH (a)	XBRL Schema Document.
101.CAL (a)	XBRL Calculation Linkbase Document.
101.DEF (a)	XBRL Definition Linkbase Document.
101.LAB (a)	XBRL Labels Linkbase Document.
101.PRE (a)	XBRL Presentation Linkbase Document.

(a)  Filed herewith.

(b)  Furnished herewith.