Edgar Filing: CONCHO RESOURCES INC

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2014

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

For the transition period from to

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)


Delaware		76-0818600
(State or other jurisdiction of		(I.R.S. Employer
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 x No ¨

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

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

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

Number of shares of the registrant’s common stock outstanding at May 8, 2014: 105,227,041 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			36

Item 3. Quantitative and Qualitative Disclosures About Market Risk			52

Item 4. Controls and Procedures			54

PART II – OTHER INFORMATION:			55

Item 1. Legal Proceedings			55

Item 1A. Risk Factors			55

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			55

Item 5. Other Information			56

Item 6. Exhibits			57

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by the forward-looking statements. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made. We disclaim any obligation to update or revise these statements unless required by law, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2013 and in this report, 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 and risks related to hydraulic fracturing activities;

•

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

•

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

•

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

•

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

•

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

•

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

•

risks and liabilities associated with acquired properties or businesses;

•

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

•

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

•

general economic and business conditions, either internationally or domestically;

•

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.

PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)


Consolidated Balance Sheets at March 31, 2014 and December 31, 2013			1

Consolidated Statements of Operations for the Three Months Ended March 31, 2014 and 2013			2

Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2014			3

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013			4

Condensed Notes to Consolidated Financial Statements			5

iii

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited


	March 31,			December 31,
(in thousands, except share and per share amounts)	2014			2013
Assets
Current assets:
Cash and cash equivalents	$	21		$	21
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas		266,489			223,790
Joint operations and other		249,568			247,945
Derivative instruments		1,358			590
Deferred income taxes		40,039			30,069
Prepaid costs and other		17,956			18,460

Total current assets		575,431			520,875

Property and equipment:
Oil and natural gas properties, successful efforts method		11,768,415			11,215,373
Accumulated depletion and depreciation		(2,600,913	)		(2,384,108	)

Total oil and natural gas properties, net		9,167,502			8,831,265
Other property and equipment, net		116,159			114,783

Total property and equipment, net		9,283,661			8,946,048

Deferred loan costs, net		69,701			73,048
Intangible asset - operating rights, net		28,250			28,615
Inventory		18,674			19,682
Noncurrent derivative instruments		269			966
Other assets		2,182			1,930

Total assets	$	9,978,168		$	9,591,164

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable - trade	$	34,071		$	13,936
Bank overdrafts		90,285			36,718
Revenue payable		199,292			177,617
Accrued and prepaid drilling costs		372,896			318,296
Derivative instruments		70,824			53,701
Other current liabilities		171,236			156,600

Total current liabilities		938,604			756,868

Long-term debt		3,674,434			3,630,421
Deferred income taxes		1,386,577			1,334,653
Noncurrent derivative instruments		17,814			14,088
Asset retirement obligations and other long-term liabilities		99,552			97,185
Commitments and contingencies (Note I)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 105,397,895 and 105,222,765 shares issued at March 31, 2014 and December 31, 2013, respectively		105			105
Additional paid-in capital		2,042,841			2,027,162
Retained earnings		1,832,873			1,741,566
Treasury stock, at cost; 160,597 and 127,305 shares at March 31, 2014 and December 31, 2013, respectively		(14,632	)		(10,884	)

Total stockholders’ equity		3,861,187			3,757,949

Total liabilities and stockholders’ equity	$	9,978,168		$	9,591,164

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

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited


	Three Months Ended March 31,
(in thousands, except per share amounts)	2014			2013
Operating revenues:
Oil sales	$	539,857		$	393,208
Natural gas sales		121,102			78,919

Total operating revenues		660,959			472,127

Operating costs and expenses:
Oil and natural gas production		126,924			100,845
Exploration and abandonments		25,375			18,407
Depreciation, depletion and amortization		221,392			168,420
Accretion of discount on asset retirement obligations		1,671			1,394
General and administrative (including non-cash stock-based compensation of $11,432 and $6,767 for the three months ended March 31, 2014 and 2013, respectively)		47,750			43,293
Loss on derivatives not designated as hedges		35,615			59,017

Total operating costs and expenses		458,727			391,376

Income from operations		202,232			80,751

Other income (expense):
Interest expense		(56,135	)		(52,106	)
Other, net		541			(109	)

Total other expense		(55,594	)		(52,215	)

Income from continuing operations before income taxes		146,638			28,536
Income tax expense		(55,331	)		(10,977	)

Income from continuing operations		91,307			17,559
Income from discontinued operations, net of tax		—			12,534

Net income	$	91,307		$	30,093

Basic earnings per share:
Income from continuing operations	$	0.87		$	0.17
Income from discontinued operations, net of tax		—			0.12

Net income	$	0.87		$	0.29

Diluted earnings per share:
Income from continuing operations	$	0.87		$	0.17
Income from discontinued operations, net of tax		—			0.12

Net income	$	0.87		$	0.29

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

Concho Resources Inc.

Consolidated Statement of Stockholders’ Equity

Unaudited


						Additional									Total
	Common Stock Issued					Paid-in		Retained		Treasury Stock					Stockholders’
(in thousands)	Shares			Amount		Capital		Earnings		Shares		Amount			Equity
BALANCE AT DECEMBER 31, 2013		105,223		$	105	$	2,027,162	$	1,741,566		127	$	(10,884	)	$	3,757,949
Net income		—			—		—		91,307		—		—			91,307
Stock options exercised		61			—		1,254		—		—		—			1,254
Grants of restricted stock		135			—		—		—		—		—			—
Cancellation of restricted stock		(21	)		—		—		—		—		—			—
Stock-based compensation		—			—		11,432		—		—		—			11,432
Excess tax benefits related to stock-based compensation		—			—		2,993		—		—		—			2,993
Purchase of treasury stock		—			—		—		—		34		(3,748	)		(3,748	)

BALANCE AT MARCH 31, 2014		105,398		$	105	$	2,042,841	$	1,832,873		161	$	(14,632	)	$	3,861,187

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

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited


	Three Months Ended March 31,
(in thousands)	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	91,307		$	30,093
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		221,392			168,420
Accretion of discount on asset retirement obligations		1,671			1,394
Exploration and abandonments, including dry holes		23,759			4,478
Non-cash stock-based compensation expense		11,432			6,767
Deferred income taxes		41,954			11,500
(Gain) loss on disposition of assets, net		(146	)		5
Loss on derivatives not designated as hedges		35,615			59,017
Discontinued operations		—			(19,754	)
Other non-cash items		2,710			3,376
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable		(10,139	)		12,608
Prepaid costs and other		21			726
Inventory		1,126			(21	)
Accounts payable		20,087			(27,679	)
Revenue payable		21,675			(15,636	)
Other current liabilities		13,516			(15,623	)

Net cash provided by operating activities		475,980			219,671

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and natural gas properties		(554,266	)		(419,766	)
Additions to other property and equipment		(5,617	)		(4,244	)
Proceeds from the disposition of assets		24			15,865
Settlements received from (paid on) derivatives not designated as hedges		(14,837	)		6,016

Net cash used in investing activities		(574,696	)		(402,129	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt		593,400			626,700
Payments of debt		(548,750	)		(463,300	)
Exercise of stock options		1,254			2,059
Excess tax benefit from stock-based compensation		2,993			3,277
Purchase of treasury stock		(3,748	)		(2,909	)
Bank overdrafts		53,567			14,725

Net cash provided by financing activities		98,716			180,552

Net decrease in cash and cash equivalents		—			(1,906	)
Cash and cash equivalents at beginning of period		21			2,880

Cash and cash equivalents at end of period	$	21		$	974

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

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Note A. Organization and nature of operations

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

Note B. Summary of significant accounting policies

Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its wholly-owned subsidiaries. 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 (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, the asset retirement obligations, fair value of derivative financial instruments, the 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, 2013 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, 2013.

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 $69.7 million and $73.0 million, net of accumulated amortization of $52.1 million and $48.7 million, at March 31, 2014 and December 31, 2013, respectively.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

The following table reflects the future amortization expense of deferred loan costs at March 31, 2014:


(in thousands)
Remaining 2014	$	10,156
2015		13,820
2016		8,476
2017		5,994
2018		6,376
2019		6,784
Thereafter		18,095

Total	$	69,701

Intangible assets. The Company has capitalized certain operating rights acquired in an acquisition. The gross operating rights, which have no residual value, are amortized over the estimated economic life of 25 years. Impairment will be assessed if indicators of potential impairment exist or when there is a material change in the remaining useful economic life. The following table reflects the gross and net intangible assets at March 31, 2014 and December 31, 2013:


	March 31,			December 31,
(in thousands)	2014			2013
Gross intangible - operating rights	$	36,557		$	36,557
Accumulated amortization		(8,307	)		(7,942	)

Net intangible - operating rights	$	28,250		$	28,615

The following table reflects amortization expense for the three months ended March 31, 2014 and 2013:


	Three Months Ended March 31,
(in thousands)	2014		2013
Amortization expense	$	365	$	365

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

The following table reflects the estimated aggregate amortization expense for each of the periods presented below at March 31, 2014:


(in thousands)
Remaining 2014	$	1,096
2015		1,461
2016		1,461
2017		1,461
2018		1,461
2019		1,461
Thereafter		19,849

Total	$	28,250

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 share of 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 $5.1 million and $4.2 million for the three months ended March 31, 2014 and 2013, respectively.

Recent accounting pronouncements. In April 2014, the Financial Accounting Standards Board issued guidance that raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. Under the revised standard, a discontinued operation is (i) a component of an entity or group of components that has been disposed of by sale, disposed of other than by sale or is classified as held for sale that represents a strategic shift that has or will have a major effect on an entity’s operations and financial results or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of the acquisition. This update is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results.

An entity is required to apply this guidance for annual reporting periods beginning on or after December 15, 2014, and interim periods within those annual periods, though earlier adoption is permitted. An entity should provide the disclosures required by this amendment prospectively. The Company is evaluating the impact of this new guidance and does not expect it to have a significant impact on the consolidated financial statements.

Note C. Exploratory well costs

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. 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 Q 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.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

The following table reflects the Company’s net capitalized exploratory well activity during the three months ended March 31, 2014:


	Three Months Ended
(in thousands)	March 31, 2014
Beginning capitalized exploratory well costs	$	144,504
Additions to exploratory well costs pending the determination of proved reserves		134,660
Reclassifications due to determination of proved reserves		(86,904	)
Exploratory well costs charged to expense		(19,286	)

Ending capitalized exploratory well costs	$	172,974

The following table provides an aging at March 31, 2014 and December 31, 2013 of capitalized exploratory well costs based on the date drilling was completed:


	March 31,		December 31,
(dollars in thousands)	2014		2013
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	152,891	$	122,753
Capitalized exploratory well costs that have been capitalized for a period greater than one year		20,083		21,751

Total capitalized exploratory well costs	$	172,974	$	144,504

Number of projects with exploratory well costs that have been capitalized for a period greater than one year		12		10

Southern Delaware Basin projects. At March 31, 2014, the Company had approximately $8.9 million of suspended well costs greater than one year recorded for two vertical wells where multiple zones are being evaluated in the Company’s Southern Delaware Basin project. The Company is assessing options to drill horizontal laterals to continue evaluation of the targets.

Other projects. At March 31, 2014, the Company had approximately $4.9 million of suspended well costs greater than one year recorded for four wells that have encountered technical difficulties that the Company plans to recomplete.

Projects operated by others. At March 31, 2014, the Company had approximately $6.2 million of suspended well costs greater than one year recorded for six wells that are operated by others and waiting on completion.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Note D. 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 three months ended March 31, 2014 and 2013:


	Three Months Ended March 31,
(in thousands)	2014			2013
Asset retirement obligations, beginning of period	$	101,593		$	86,261
Liabilities incurred from new wells		995			1,592
Liabilities assumed in acquisitions		200			161
Accretion expense		1,671			1,394
Liabilities settled upon plugging and abandoning wells		(524	)		(1,157	)
Revision of estimates		528			672

Asset retirement obligations, end of period	$	104,463		$	88,923

Note E. Incentive plans

Defined contribution plan. The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees. Currently, the Company matches 100 percent of employee contributions, not to exceed 10 percent of the employee’s annual salary. The Company’s contributions to the plan for the three months ended March 31, 2014 and 2013, were approximately $1.9 million and $1.2 million, respectively, of which a portion was recoverable from other working interest owners.

Stock incentive plan. The Company’s 2006 Stock Incentive Plan, as amended and restated (the “Plan”), provides for granting stock options, restricted stock awards and performance awards to directors, officers and employees of the Company.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Restricted stock awards. All restricted shares are legally issued and outstanding. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and cancelled and are no longer considered issued and outstanding. A summary of the Company’s restricted stock award activity for the three months ended March 31, 2014 is presented below:


				Weighted
				Average
	Number of			Grant Date
	Restricted			Fair Value
	Shares			Per Share
Restricted stock:
Outstanding at December 31, 2013		1,216,449
Shares granted		134,989		$	108.42
Shares cancelled / forfeited		(20,535	)
Lapse of restrictions		(117,481	)

Outstanding at March 31, 2014		1,213,422

For restricted stock awards granted, stock-based compensation expense is being recognized in the Company’s financial statements on an accelerated basis over the awards’ vesting periods based on their fair values on the dates of grant. The restricted stock-based compensation awards generally vest over a period ranging from one to five years. The Company utilizes the average of the grant date’s high and low stock prices for the fair value of restricted stock.

The following table summarizes information about stock-based compensation for the Company’s restricted stock awards activity under the Plan for the three months ended March 31, 2014 and 2013:


	Three Months Ended March 31,
(in thousands)	2014		2013
*Grant date fair value for awards during the period (a)*	$	14,636	$	11,979
*Stock-based compensation expense from restricted stock*	$	8,839	$	5,760
*Income taxes and other information:*
Income tax benefit related to restricted stock	$	2,915	$	2,202
Deductions in current taxable income related to restricted stock vestings	$	12,663	$	9,790

(a)	The three months ended March 31, 2013 includes the effects of $1 million due to modifications of certain stock-based awards.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Stock option awards. A summary of the Company’s stock option award activity under the Plan for the three months ended March 31, 2014 is presented below:


				Weighted
				Average
	Number of			Exercise
	Options			Price
*Stock options:*
Outstanding at December 31, 2013		255,537		$	21.50
Options exercised		(60,676	)	$	20.67

Outstanding at March 31, 2014		194,861		$	21.76

Vested and exercisable at end of period		194,861		$	21.76

The intrinsic value of options exercised during the three months ended March 31, 2014 and 2013 was approximately $6.1 million and $8.5 million, respectively, based on the difference between the market price at the exercise date and the option exercise price.

The following table summarizes information about the Company’s vested and exercisable stock options outstanding at March 31, 2014:


			Weighted
			Average		Weighted		Intrinsic
Range of			Remaining		Average		Value
Exercise	Number		Contractual		Exercise		of
Prices	Vested		Life		Price		Options
							(in thousands)
Vested and exercisable options:
$12.00		8,536		1.74 years	$	12.00	$	943
$12.50 - $15.50		15,000		3.38 years	$	12.85		1,645
$20.00 - $23.00		140,770		4.41 years	$	21.23		14,256
$28.00 - $37.27		30,555		4.14 years	$	31.33		2,786

		194,861		4.17 years	$	21.76	$	19,630

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

The following table summarizes information about stock-based compensation for stock options for the three months ended March 31, 2014 and 2013:


	Three Months Ended
	March 31,
(in thousands)	2014		2013
*Stock-based compensation expense from stock options*	$	—	$	14
*Income taxes and other information:*
Income tax benefit related to stock options	$	—	$	5
Deductions in current taxable income related to stock options exercised	$	6,138	$	8,501

Performance unit awards. During the three months ended March 31, 2014 and 2013, the Company awarded performance units to its officers under the Plan. The number of shares of common stock that will ultimately be issued 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 grant date fair value was determined using the Monte Carlo simulation method and is being expensed ratably over the performance period. Expected volatilities utilized in the model were estimated using a historical period consistent with the remaining performance period of approximately three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant.

The Company used the following assumptions to estimate the fair value of performance unit awards granted during the three months ended March 31, 2014 and 2013:


	Three Months Ended
	March 31,
	2014	2013
Risk-free interest rate	0.76%	0.37%
Range of volatilities	29.2% - 42.2%	31.5% - 45.1%

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

The following table summarizes the performance unit activity for the three months ended March 31, 2014:


	Number of		Grant Date
	Units (a)		Fair Value
Performance units:
Outstanding at December 31, 2013		110,889
Units granted		139,425	$	139.54

Outstanding at March 31, 2014		250,314

(a)	Reflects the amount of performance units granted. 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.

The following table summarizes information about stock-based compensation expense for performance units for the three months ended March 31, 2014:


	Three Months Ended
	March 31,
(in thousands)	2014		2013
Grant date fair value for awards during the period	$	19,455	$	12,353
Stock-based compensation expense from performance units	$	2,593	$	993
Income tax benefit related to performance units	$	975	$	380

Future stock-based compensation expense. The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at March 31, 2014:


	Restricted		Performance
(in thousands)	Stock		Units		Total
Remaining 2014	$	24,473	$	7,952	$	32,425
2015		18,531		10,639		29,170
2016		8,136		6,543		14,679
2017		1,670		—		1,670
2018		263		—		263
Thereafter		3		—		3

Total	$	53,076	$	25,134	$	78,210

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Note F. Disclosures about fair value of financial instruments

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



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

		*Level 2*:		Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, 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 and (iii) current market and contractual prices for the underlying instruments, 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.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

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 March 31, 2014 and December 31, 2013:


	March 31, 2014				December 31, 2013
	Carrying		Fair		Carrying		Fair
(in thousands)	Value		Value		Value		Value
Assets:
Derivative instruments	$	1,627	$	1,627	$	1,556	$	1,556
Liabilities:
Derivative instruments	$	88,638	$	88,638	$	67,789	$	67,789
Credit facility	$	294,650	$	298,722	$	250,000	$	250,770
7.0% senior notes due 2021	$	600,000	$	661,500	$	600,000	$	660,000
6.5% senior notes due 2022	$	600,000	$	654,000	$	600,000	$	649,500
5.5% senior notes due 2022	$	600,000	$	625,500	$	600,000	$	619,500
5.5% senior notes due 2023	$	1,579,784	$	1,642,975	$	1,580,421	$	1,627,834

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

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

Concentrations of credit risk. As of March 31, 2014, the Company’s primary concentration of credit risks are the risk of collecting accounts receivable – trade 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 G for additional information regarding the Company’s derivative activities.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table summarizes (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at March 31, 2014 and December 31, 2013. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.


March 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	$	—	$	32,599		$	—	$	32,599		$	(31,241	)	$	1,358
Noncurrent:
Commodity derivatives		—		4,334			—		4,334			(4,065	)		269
Liabilities
Current:
Commodity derivatives		—		(102,065	)		—		(102,065	)		31,241			(70,824	)
Noncurrent:
Commodity derivatives		—		(21,879	)		—		(21,879	)		4,065			(17,814	)

Net derivative instruments	$	—	$	(87,011	)	$	—	$	(87,011	)	$	—		$	(87,011	)

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited


December 31, 2013
	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	$	—	$	12,819		$	—	$	12,819		$	(12,229	)	$	590
Noncurrent:
Commodity derivatives		—		5,300			—		5,300			(4,334	)		966
Liabilities
Current:
Commodity derivatives		—		(65,930	)		—		(65,930	)		12,229			(53,701	)
Noncurrent:
Commodity derivatives		—		(18,422	)		—		(18,422	)		4,334			(14,088	)

Net derivative instruments	$	—	$	(66,233	)	$	—	$	(66,233	)	$	—		$	(66,233	)

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

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 did not recognize any impairment charges for the three months ended March 31, 2014 or 2013.

Note G. 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 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.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

The following table summarizes the losses reported in earnings related to the commodity derivative instruments for the three months ended March 31, 2014 and 2013:


	Three Months Ended
	March 31,
(in thousands)	2014			2013
*Loss on derivatives not designated as hedges:*
Oil derivatives	$	(24,220	)	$	(59,017	)
Natural gas derivatives		(11,395	)		—

Total loss on derivatives not designated as hedges	$	(35,615	)	$	(59,017	)

The following table represents the Company’s cash receipts from (payments on) derivatives reported in the Company’s cash flows from investing for the three months ended March 31, 2014 and 2013:


	Three Months Ended
	March 31,
(in thousands)	2014			2013
*Cash receipts from (payments on) derivatives not designated as hedges:*
Oil derivatives	$	(9,769	)	$	6,016
Natural gas derivatives		(5,068	)		—

Total cash receipts from (payments on) derivatives not designated as hedges	$	(14,837	)	$	6,016

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Commodity derivative contracts at March 31, 2014. The following table sets forth the Company’s outstanding derivative contracts at March 31, 2014. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at March 31, 2014 are expected to settle by June 30, 2017.


	First		Second			Third			Fourth
	Quarter		Quarter			Quarter			Quarter			Total
Oil Swaps: (a)
*2014:*
Volume (Bbl)				4,544,000			4,116,000			3,833,000			12,493,000
Price per Bbl			$	92.69		$	91.23		$	91.09		$	91.72
*2015:*
Volume (Bbl)		3,428,000		3,264,000			3,123,000			2,997,000			12,812,000
Price per Bbl	$	87.33	$	86.54		$	86.80		$	86.75		$	86.86
*2016:*
Volume (Bbl)		108,000		108,000			108,000			105,000			429,000
Price per Bbl	$	88.32	$	88.32		$	88.32		$	88.28		$	88.31
*2017:*
Volume (Bbl)		84,000		84,000			—			—			168,000
Price per Bbl	$	87.00	$	87.00		$	—		$	—		$	87.00
Oil Basis Swaps: (b)
*2014:*
Volume (Bbl)				3,458,000			3,956,000			3,680,000			11,094,000
Price per Bbl			$	(0.72	)	$	(0.99	)	$	(0.92	)	$	(0.88	)
Natural Gas Swaps: (c)
*2014:*
Volume (MMBtu)				3,335,000			2,576,000			2,053,000			7,964,000
Price per MMBtu			$	4.22		$	4.23		$	4.24		$	4.23
*2015:*
Volume (MMBtu)		5,850,000		5,915,000			5,980,000			5,980,000			23,725,000
Price per MMBtu	$	4.16	$	4.16		$	4.16		$	4.16		$	4.16
Natural Gas Collars: (d)
*2014:*
Volume (MMBtu)				5,460,000			5,520,000			5,520,000			16,500,000
Ceiling price per MMBtu			$	4.40		$	4.40		$	4.40		$	4.40
Floor price per MMBtu			$	3.85		$	3.85		$	3.85		$	3.85

(a)	The index prices for the oil price swaps are based on the 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 index prices for the natural gas collars are based on the El Paso Permian delivery point.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Derivative counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures.

Note H. Debt

The Company’s debt consisted of the following at March 31, 2014 and December 31, 2013:


	March 31,		December 31,
(in thousands)	2014		2013
Credit facility	$	294,650	$	250,000
7.0% unsecured senior notes due 2021		600,000		600,000
6.5% unsecured senior notes due 2022		600,000		600,000
5.5% unsecured senior notes due 2022		600,000		600,000
5.5% unsecured senior notes due 2023		1,550,000		1,550,000
Unamortized original issue premium, net		29,784		30,421
Less: current portion		—		—

Total long-term debt	$	3,674,434	$	3,630,421

Credit facility. The Company’s credit facility, as of March 31, 2014, has a maturity date of April 25, 2016. As of March 31, 2014, the Company’s borrowing base is $3.0 billion and commitments from the Company’s bank group total $2.5 billion. See Note P for a subsequent event regarding the Company’s amended and restated credit facility that was executed on May 9, 2014.

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 O.

At March 31, 2014, the Company was in compliance with the covenants under all of its debt instruments.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Future benefit to interest expense from original issue premium at March 31, 2014 was as follows:


(in thousands)
Remaining 2014	$	1,964
2015		2,747
2016		2,900
2017		3,062
2018		3,233
2019		3,413
Thereafter		12,465

Total	$	29,784

Principal maturities of long-term debt. Principal maturities of long-term debt outstanding at March 31, 2014 were as follows:


(in thousands)
Remaining 2014	$	—
2015		—
2016		294,650
2017		—
2018		—
2019		—
Thereafter		3,350,000

Total	$	3,644,650

Interest expense. The following amounts have been incurred and charged to interest expense for the three months ended March 31, 2014 and 2013:


	Three Months Ended
	March 31,
(in thousands)	2014			2013
Cash payments for interest	$	44,320		$	43,988
Amortization of original issue discount (premium)		(637	)		123
Amortization of deferred loan origination costs		3,347			3,254
Net changes in accruals		9,105			4,741

Total interest expense	$	56,135		$	52,106

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Note I. 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 $7.0 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 March 31, 2014 and December 31, 2013, the Company had $12.7 million and $12.2 million accrued for estimated exposure, respectively. Although we believe that we have estimated our 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.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Contractual drilling commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future, including agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments in the periods in which well capital is incurred or rig services are provided. The following table summarizes the Company’s future drilling commitments at March 31, 2014:


	Payments Due By Period
			Less than		1-3		3-5		More than
(in thousands)	Total		1 year		years		years		5 years
Contractual drilling commitments	$	11,288	$	11,288	$	—	$	—	$	—

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 March 31, 2014 and 2013 were approximately $1.7 million and $1.2 million, respectively.

Future minimum lease commitments under non-cancellable operating leases at March 31, 2014 were as follows:


(in thousands)
Remaining 2014	$	4,966
2015		5,546
2016		4,202
2017		4,411
2018		3,928
2019		3,980
Thereafter		8,659

Total	$	35,692

Note J. Income taxes

The effective income tax rates for the three months ended March 31, 2014 and 2013 were 37.7 percent and 38.5 percent, respectively. During the fourth quarter of 2013, the Company revised its estimated blended effective state rate to consider (a) New Mexico legislation passed that phases in a tax rate reduction from 7.6 percent to 5.9 percent in 2018 and (b) the apportionment factor for states in which the Company operates. Total income tax expense for the three months ended March 31, 2014 and 2013 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to state taxes and the impact of permanent differences between book and taxable income.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Note K. 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
	March 31,
(in thousands)	2014		2013
Royalties paid to a partnership in which a director has an ownership interest (a)	$	2,802	$	1,340
Royalties paid to a director and certain officers of the Company (b)	$	97	$	10
Amounts paid under consulting agreement with Steven L. Beal (c)	$	—	$	60

(a)	Royalties paid on certain properties to a partnership of which a director of the Company is the general partner and owns a 3.5 percent partnership interest.

(b)	Payments made to a director and certain officers who directly own overriding royalty interests in properties owned by the Company.

(c)

On June 30, 2009, Steven L. Beal, the Company’s then-president and chief operating officer, retired from such positions. On June 9, 2009, the Company entered into a consulting agreement (the “Consulting Agreement”) with Mr. Beal, under which Mr. Beal began serving as a consultant to the Company on July 1, 2009. During the term of the consulting relationship, Mr. Beal received a consulting fee of $20,000 per month and a monthly reimbursement for his medical and dental coverage costs. In August 2013, the Company and Mr. Beal mutually terminated the Consulting Agreement in exchange for the payment to Mr. Beal of $720,000, which termination and payment were approved by the disinterested members of the Company’s Board of Directors.

Note L. Discontinued operations

In December 2012, the Company closed the sale of certain of its non-core assets for cash consideration of approximately $503.1 million. As a result of post-closing adjustments during the three months ended March 31, 2013, the Company made a positive adjustment to gain (loss) on disposition of assets of approximately $20.4 million, before income tax expense of approximately $7.9 million. The Company reflected the net post-closing adjustment of approximately $12.5 million as discontinued operations.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Note M. 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. Participating securities participate in income proportionate to the weighted average number of outstanding common shares (although all restricted stock is issued and outstanding upon grant), but are not assumed to participate in the Company’s net losses because they are not contractually obligated to do so. Accordingly, allocations of earnings to participating securities are included in the Company’s calculations of basic and diluted earnings per share from continuing operations, discontinued operations and net income attributable to common stockholders.

The following tables reconcile the Company’s income from continuing operations, income from discontinued operations and net income attributable to common stockholders to the basic and diluted earnings used to determine the Company’s income per share amounts for the three months ended March 31, 2014 and 2013, respectively, under the two-class method:


	Three Months Ended
	March 31, 2014
	Continuing			Discontinued
(in thousands, except per share amounts)	Operations			Operations		Total
Income as reported	$	91,307		$	—	$	91,307
Participating basic earnings		(1,068	)		—		(1,068	)

Basic income attributable to common stockholders		90,239			—		90,239
Reallocation of participating earnings		4			—		4

Diluted income attributable to common stockholders	$	90,243		$	—	$	90,243

Income per common share:
Basic	$	0.87		$	—	$	0.87
Diluted	$	0.87		$	—	$	0.87

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited


	Three Months Ended
	March 31, 2013
	Continuing		Discontinued
(in thousands, except per share amounts)	Operations		Operations		Total
Income as reported	$	17,559	$	12,534	$	30,093
Participating basic earnings		—		—		—

Basic income attributable to common stockholders		17,559		12,534		30,093
Reallocation of participating earnings		—		—		—

Diluted income attributable to common stockholders	$	17,559	$	12,534	$	30,093

Income per common share:
Basic	$	0.17	$	0.12	$	0.29
Diluted	$	0.17	$	0.12	$	0.29

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three months ended March 31, 2014 and 2013:


	Three Months Ended
	March 31,
(in thousands)	2014		2013
Weighted average common shares outstanding:
Basic		103,949		103,631
Dilutive common stock options		123		204
Dilutive restricted stock		—		510
Dilutive performance units		234		—

Diluted		104,306		104,345

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


	Three Months Ended
	March 31,
(in thousands)	2014		2013
Number of antidilutive common shares:
Antidilutive restricted stock		46		13
Antidilutive performance units		—		111

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Note N. Other current liabilities

The following table provides the components of the Company’s other current liabilities at March 31, 2014 and December 31, 2013:


	March 31,		December 31,
(in thousands)	2014		2013
*Other current liabilities:*
Accrued production costs	$	46,553	$	48,196
Payroll related matters		30,863		28,498
Accrued interest		79,105		70,000
Settlements due on derivatives		2,993		1,175
Asset retirement obligations		4,982		4,481
Other		6,740		4,250

Other current liabilities	$	171,236	$	156,600

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Note O. Subsidiary guarantors

Certain of the Company’s wholly-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 released in 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 H 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 March 31, 2014 and December 31, 2013, condensed consolidating statements of operations and condensed consolidating statements of cash flows for the three months ended March 31, 2014 and 2013 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.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Condensed Consolidating Balance Sheet

March 31, 2014


	Parent		Subsidiary		Consolidating
(in thousands)	Issuer		Guarantors		Entries			Total
ASSETS
Accounts receivable—related parties	$	6,092,946	$	1,244,197	$	(7,337,143	)	$	—
Other current assets		40,628		534,803		—			575,431
Oil and natural gas properties, net		—		9,167,502		—			9,167,502
Property and equipment, net		—		116,159		—			116,159
Investment in subsidiaries		4,135,667		—		(4,135,667	)		—
Other long-term assets		69,970		49,106		—			119,076

Total assets	$	10,339,211	$	11,111,767	$	(11,472,810	)	$	9,978,168

LIABILITIES AND EQUITY
Accounts payable—related parties	$	1,244,197	$	6,092,946	$	(7,337,143	)	$	—
Other current liabilities		155,002		783,602		—			938,604
Other long-term liabilities		1,404,391		99,552		—			1,503,943
Long-term debt		3,674,434		—		—			3,674,434
Equity		3,861,187		4,135,667		(4,135,667	)		3,861,187

Total liabilities and equity	$	10,339,211	$	11,111,767	$	(11,472,810	)	$	9,978,168

Condensed Consolidating Balance Sheet

December 31, 2013


	Parent		Subsidiary		Consolidating
(in thousands)	Issuer		Guarantors		Entries			Total
ASSETS
Accounts receivable—related parties	$	6,115,554	$	1,261,844	$	(7,377,398	)	$	—
Other current assets		39,108		481,767		—			520,875
Oil and natural gas properties, net		—		8,831,265		—			8,831,265
Property and equipment, net		—		114,783		—			114,783
Investment in subsidiaries		3,896,741		—		(3,896,741	)		—
Other long-term assets		74,013		50,228		—			124,241

Total assets	$	10,125,416	$	10,739,887	$	(11,274,139	)	$	9,591,164

LIABILITIES AND EQUITY
Accounts payable—related parties	$	1,261,844	$	6,115,554	$	(7,377,398	)	$	—
Other current liabilities		126,461		630,407		—			756,868
Other long-term liabilities		1,348,741		97,185		—			1,445,926
Long-term debt		3,630,421		—		—			3,630,421
Equity		3,757,949		3,896,741		(3,896,741	)		3,757,949

Total liabilities and equity	$	10,125,416	$	10,739,887	$	(11,274,139	)	$	9,591,164

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2014


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries			Total
Total operating revenues	$	—		$	660,959		$	—		$	660,959
Total operating costs and expenses		(36,153	)		(422,574	)		—			(458,727	)

Income (loss) from operations		(36,153	)		238,385			—			202,232
Interest expense		(56,135	)		—			—			(56,135	)
Other, net		238,926			541			(238,926	)		541

Income before income taxes		146,638			238,926			(238,926	)		146,638
Income tax expense		(55,331	)		—			—			(55,331	)

Net income	$	91,307		$	238,926		$	(238,926	)	$	91,307

Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2013


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries			Total
Total operating revenues	$	—		$	472,127		$	—		$	472,127
Total operating costs and expenses		(59,196	)		(332,180	)		—			(391,376	)

Income (loss) from continuing operations		(59,196	)		139,947			—			80,751
Interest expense		(52,106	)		—			—			(52,106	)
Other, net		160,201			(109	)		(160,201	)		(109	)

Income from continuing operations before income taxes		48,899			139,838			(160,201	)		28,536
Income tax expense		(10,977	)		—			—			(10,977	)

Income from continuing operations		37,922			139,838			(160,201	)		17,559
Income (loss) from discontinued operations, net of tax		(7,829	)		20,363			—			12,534

Net income	$	30,093		$	160,201		$	(160,201	)	$	30,093

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2014


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries		Total
Net cash flows provided by (used in) operating activities	$	(30,312	)	$	506,292		$	—	$	475,980
Net cash flows used in investing activities		(14,837	)		(559,859	)		—		(574,696	)
Net cash flows provided by financing activities		45,149			53,567			—		98,716

Net decrease in cash and cash equivalents		—			—			—		—
Cash and cash equivalents at beginning of period		—			21			—		21

Cash and cash equivalents at end of period	$	—		$	21		$	—	$	21

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2013


	Parent			Subsidiary			Consolidating
(in thousands)	Issuer			Guarantors			Entries		Total
Net cash flows provided by (used in) operating activities	$	(171,843	)	$	391,514		$	—	$	219,671
Net cash flows provided by (used in) investing activities		6,016			(408,145	)		—		(402,129	)
Net cash flows provided by financing activities		165,827			14,725			—		180,552

Net decrease in cash and cash equivalents		—			(1,906	)		—		(1,906	)
Cash and cash equivalents at beginning of period		—			2,880			—		2,880

Cash and cash equivalents at end of period	$	—		$	974		$	—	$	974

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Note P. Subsequent events

New commodity derivative contracts. After March 31, 2014, the Company entered into the following oil price swaps, oil basis swaps and natural gas basis swaps to hedge additional amounts of the Company’s estimated future production:


	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter			Total
Oil Swaps: (a)
*2014:*
Volume (Bbl)					440,000			455,000			340,000			1,235,000
Price per Bbl				$	99.90		$	99.53		$	99.12		$	99.55
*2015:*
Volume (Bbl)		360,000			360,000			210,000			210,000			1,140,000
Price per Bbl	$	91.50		$	91.50		$	90.76		$	90.76		$	91.23
Oil Basis Swaps: (b)
*2014:*
Volume (Bbl)					—			—			276,000			276,000
Price per Bbl				$	—		$	—		$	(3.00	)	$	(3.00	)
*2015:*
Volume (Bbl)		270,000			273,000			—			—			543,000
Price per Bbl	$	(3.00	)	$	(3.00	)	$	—		$	—		$	(3.00	)
Natural Gas Basis Swaps: (c)
*2014:*
Volume (MMBtu)					1,220,000			1,840,000			1,840,000			4,900,000
Price per MMBtu				$	(0.11	)	$	(0.11	)	$	(0.11	)	$	(0.11	)

(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 basis differential price is between the El Paso Permian delivery point and NYMEX – Henry Hub delivery point.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Delaware Basin midstream agreements. On May 9, 2014, the Company signed an agreement, with an unrelated third party, to own 50 percent of a new midstream joint venture. The joint venture was formed to build a crude oil pipeline to transport production in the northern Delaware Basin. The Company’s 50 percent share of the joint venture’s capital expenditures is estimated to be approximately $95.0 million. The Company expects the system to be operational in the second half of 2015.

Additionally, on May 9, 2014, the Company entered into a ten year crude petroleum dedication and transportation agreement with the joint venture. Under the terms of the agreement and subject to certain regulatory approvals, the Company is obligated to deliver oil production to the joint venture from a substantial portion of the properties that the Company currently operates in the northern Delaware Basin area, as well as oil production from future development of certain of the Company’s northern Delaware Basin acreage.

Amended and restated credit facility. On May 9, 2014, the Company amended and restated its credit facility. The Company increased its borrowing base from $3.0 billion to $3.25 billion while maintaining the aggregate lender commitments at $2.5 billion. The maturity date of the amended and restated credit facility is May 9, 2019. Subject to certain restrictions, with respect to the Company’s public debt ratings, the collateral securing the facility may be released. Additionally, the new facility provides for a 25 basis point reduction in the drawn spread and further interest rate reductions on the undrawn spread. The Company expects to write-off approximately $4.3 million in capitalized deferred loan costs incurred with the previous credit facility.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2014

Unaudited

Note Q. Supplementary information

Capitalized costs


	March 31,			December 31,
(in thousands)	2014			2013
*Oil and natural gas properties:*
Proved	$	10,708,779		$	10,182,953
Unproved		1,059,636			1,032,420
Less: accumulated depletion		(2,600,913	)		(2,384,108	)

Net capitalized costs for oil and natural gas properties	$	9,167,502		$	8,831,265

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


	Three Months Ended
	March 31,
(in thousands)	2014		2013
Property acquisition costs:
Proved	$	20,490	$	1,885
Unproved		24,688		27,896
Exploration		324,497		266,690
Development		211,679		174,722

Total costs incurred for oil and natural gas properties	$	581,354	$	471,193

(a)

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



	Three Months Ended
	March 31,
(in thousands)	2014		2013
Exploration costs	$	558	$	734
Development costs		965		1,530

Total asset retirement obligations	$	1,523	$	2,264

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 producing oil and natural gas properties. Our core operations are primarily focused in the Permian Basin of Southeast New Mexico and West Texas. We refer to our three core operating areas as the (i) New Mexico Shelf, where we primarily target the Yeso formation both on a vertical and horizontal basis, (ii) Delaware Basin, where we primarily target the Bone Spring formation (which includes the Avalon Shale and the Bone Spring sands) and the Wolfcamp shale, all primarily on a horizontal basis, and (iii) Texas Permian, where we primarily target the Wolfberry, a term applied to the combined Wolfcamp and Spraberry horizons, primarily on a vertical basis and the Wolfcamp shale on a horizontal basis. Oil comprised 61.1 percent of our 502.9 MMBoe of estimated proved reserves at December 31, 2013 and 63.9 percent of our 9.1 MMBoe of production for the three months ended March 31, 2014. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 91.1 percent of our proved developed producing PV-10 and 80.3 percent of our approximately 6,530 gross wells at December 31, 2013. 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 three months ended March 31, 2014, as compared to the three months ended March 31, 2013, included the following highlights:

•

Net income was $91.3 million ($0.87 per diluted share) for the first three months of 2014, as compared to net income of $30.1 million ($0.29 per diluted share) during the three months ended March 31, 2013. The increase in net income was primarily due to:

•

$188.9 million increase in oil and natural gas revenues as a result of a 18 percent increase in commodity price realizations per Boe (excluding the effects of derivative activities) and by an 18 percent increase in production; and

•

$35.6 million loss on derivatives not designated as hedges for the three months ended March 31, 2014, as compared to a $59.0 million loss on derivatives not designated as hedges during the three months ended March 31, 2013;

partially offset by

•

$53.0 million increase in depreciation, depletion and amortization (“DD&A”) expense, primarily due to capitalized costs associated with new wells that were successfully drilled and completed in 2013 and 2014;

•

$26.1 million increase in oil and natural gas production costs due in part to increased production related to our wells successfully drilled and completed in 2013 and 2014;

•

$4.0 million increase in interest expense due to a 13 percent increase in the weighted average debt balance outstanding between the periods due to capital expenditures, primarily related to our drilling program, offset in part by a lower weighted average interest rate due to our recent senior note issuances having lower interest rates than historical issuances;

•

$4.5 million increase in general and administrative expense due an increase in the number of employees and related personnel expenses to handle our increased activities related to our increased drilling and exploration activities; and

•

$12.5 million income from discontinued operations, net of tax in 2013 related to the post-closing adjustments to our sale of certain non-core assets in the fourth quarter of 2012.

•

Average daily sales volumes increased by 18 percent from 85,926 Boe per day during the first three months of 2013 to 101,623 Boe per day during the first three months of 2014. The increase is primarily attributable to our successful drilling efforts during 2013 and 2014.

•

Net cash provided by operating activities increased by approximately $256.3 million to $476.0 million for the first three months of 2014, as compared to $219.7 million in the first three months of 2013, primarily due to (i) increased oil and natural gas revenues and (ii) positive variances in working capital changes, offset by increases in related oil and natural gas production costs and interest expense.

•

Long-term debt increased by approximately $44.0 million during the first three months of 2014, primarily as a result of the spending on drilling in excess of our operating cash flow.

•

At March 31, 2014, availability under our credit facility was approximately $2.2 billion.

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, (ii) natural gas and natural gas liquids 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:

•

economic stimulus initiatives in the United States;

•

worldwide and continuing economic struggles in Eurozone nations’ economies;

•

political and economic developments in the Middle East;

•

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

•

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 and taxation;

•

the proximity, capacity, cost and availability of pipelines and other transportation facilities;

•

the quality of the oil we produce;

•

the overall global demand for oil; and

•

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

•

the United States economy impact,

•

weather conditions, and

•

liquefied natural gas deliveries to the United States.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Note G of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commodity derivative positions at March 31, 2014.

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 higher during the comparable periods of 2014 measured against 2013. The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three months ended March 31, 2014 and 2013, as well as the high and low NYMEX prices for the same periods:


	Three Months Ended
	March 31,
	2014		2013
Average NYMEX prices:
Oil (Bbl)	$	98.60	$	94.41
Natural gas (MMBtu)	$	4.72	$	3.49
High and Low NYMEX prices:
*Oil (Bbl):*
High	$	104.92	$	97.94
Low	$	91.66	$	90.12
*Natural gas (MMBtu):*
High	$	6.15	$	4.07
Low	$	4.01	$	3.11

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $104.37 and $99.42 per Bbl and $4.83 and $4.28 per MMBtu, respectively, during the period from March 31, 2014 to May 8, 2014. At May 8, 2014, the NYMEX oil price and NYMEX natural gas price were $100.26 per Bbl and $4.57 per MMBtu, respectively.

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 March 31, 2014 and 2013, the basis differential between WTI-Midland and WTI-Cushing was a price reduction of $3.53 per barrel and $7.78 per barrel, respectively, which is the primary reason for the higher realized oil price compared as a percentage to the NYMEX price in 2014. The current outlook for the basis differential between WTI-Midland and WTI-Cushing is $8.68 per barrel during April 2014 and declines to approximately $2.75 per barrel in December 2014.

Recent Events

Delaware Basin midstream agreements. On May 9, 2014, we signed an agreement to own 50 percent of a joint venture, which will build a crude oil pipeline to transport oil production in the northern Delaware Basin. Additionally, on May 9, 2014, we entered into a ten year crude petroleum dedication and transportation agreement with the joint venture to transport a substantial portion of our current and future oil production in the northern Delaware Basin. We expect to receive improved price realizations on our crude oil subject to this dedication agreement due to reduced transportation costs and increased market optionality due to concentrated volumes.

Amended and restated credit facility. On May 9, 2014, we amended and restated our credit facility, increasing our borrowing base from $3.0 billion to $3.25 billion, but maintaining the aggregate lender commitments at $2.5 billion. The maturity date of the amended and restated credit facility is May 9, 2019. We expect to write-off approximately $4.3 million in capitalized deferred loan costs incurred with the previous credit facility. For additional information about the amended and restated credit facility, see Part II, Item 5.

2014 revised capital budget. In May 2014, we increased our upstream capital budget by approximately $300 million to a total of approximately $2.6 billion, excluding the costs of acquisitions other than customary leasehold purchases of acreage, to fund our accelerated drilling in the Delaware Basin and Texas Permian. Additionally, our midstream joint venture is expected to add approximately $55.0 million to the overall 2014 capital budget. The 2014 revised capital budget, based on our current expectations of commodity prices and cost, will exceed our cash flows from operations. We expect our cash flow and borrowings under our credit facility will be sufficient to fund our budgeted capital expenditure needs during 2014. However, our capital budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in our costs, we may reduce our capital spending program to manage the level of capital outspend.

Derivative Financial Instruments

Derivative financial instrument exposure. At March 31, 2014, the fair value of our financial derivatives was a net liability of $87.0 million. 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 March 31, 2014, we entered into the following additional oil price swaps, oil basis swaps and natural gas basis swaps to hedge additional amounts of our estimated future production:


	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter			Total
Oil Swaps: (a)
*2014:*
Volume (Bbl)					440,000			455,000			340,000			1,235,000
Price per Bbl				$	99.90		$	99.53		$	99.12		$	99.55
*2015:*
Volume (Bbl)		360,000			360,000			210,000			210,000			1,140,000
Price per Bbl	$	91.50		$	91.50		$	90.76		$	90.76		$	91.23
Oil Basis Swaps: (b)
*2014:*
Volume (Bbl)					—			—			276,000			276,000
Price per Bbl				$	—		$	—		$	(3.00	)	$	(3.00	)
*2015:*
Volume (Bbl)		270,000			273,000			—			—			543,000
Price per Bbl	$	(3.00	)	$	(3.00	)	$	—		$	—		$	(3.00	)
Natural Gas Basis Swaps: (c)
*2014:*
Volume (MMBtu)					1,220,000			1,840,000			1,840,000			4,900,000
Price per MMBtu				$	(0.11	)	$	(0.11	)	$	(0.11	)	$	(0.11	)

(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 basis differential price is between the El Paso Permian delivery point and NYMEX – Henry Hub delivery point.

Results of Operations

The following table sets forth summary information concerning our production and operating data for the three months ended March 31, 2014 and 2013. 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
	March 31,
	2014		2013
*Production and operating data:*
Net production volumes:
Oil (MBbl)		5,846		4,767
Natural gas (MMcf)		19,800		17,798
Total (MBoe)		9,146		7,733
Average daily production volumes:
Oil (Bbl)		64,956		52,967
Natural gas (Mcf)		220,000		197,756
Total (Boe)		101,623		85,926
Average prices:
Oil, without derivatives (Bbl)	$	92.35	$	82.49
Oil, with derivatives (Bbl) (a)	$	90.68	$	83.75
Natural gas, without derivatives (Mcf)	$	6.12	$	4.43
Natural gas, with derivatives (Mcf) (a)	$	5.86	$	4.43
Total, without derivatives (Boe)	$	72.27	$	61.05
Total, with derivatives (Boe) (a)	$	70.65	$	61.83
Operating costs and expenses per Boe:
Lease operating expenses and workover costs	$	8.07	$	7.74
Oil and natural gas taxes	$	5.80	$	5.31
Depreciation, depletion and amortization	$	24.21	$	21.79
General and administrative	$	5.22	$	5.60

(a)	Includes the effect of cash settlements received from (paid on) commodity derivatives not designated as hedges:



	Three Months Ended
	March 31,
(in thousands)	2014			2013
Cash receipts from (payments on) derivatives not designated as hedges:
Oil derivatives	$	(9,769	)	$	6,016
Natural gas derivatives		(5,068	)		—

Total cash receipts from (payments on) derivatives	$	(14,837	)	$	6,016

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.

Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

Oil and natural gas revenues. Revenue from oil and natural gas operations was $661.0 million for the three months ended March 31, 2014, an increase of $188.9 million (40 percent) from $472.1 million for the three months ended March 31, 2013. This increase was primarily due to an increase in the realized oil and natural gas prices as well as increased production due to our successful drilling efforts during 2013 and 2014. Specific factors affecting oil and natural gas revenues include the following:

•

total oil production was 5,846 MBbl for the three months ended March 31, 2014, an increase of 1,079 MBbl (23 percent) from 4,767 MBbl for the three months ended March 31, 2013;

•

average realized oil price (excluding the effects of derivative activities) was $92.35 per Bbl during the three months ended March 31, 2014, an increase of 12 percent from $82.49 per Bbl during the three months ended March 31, 2013. For the three months ended March 31, 2014 and 2013, we realized approximately 93.7 percent and 87.3 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 March 31, 2014 and 2013, the basis differential between WTI-Midland and WTI-Cushing was a price reduction of $3.53 per barrel and $7.78 per barrel, respectively, which is the primary reason for the higher realized oil price compared as a percentage to the NYMEX price in 2014. The current outlook for the basis differential between WTI-Midland and WTI-Cushing is $8.68 per barrel in April 2014 and declines to approximately $2.75 in December 2014.

•

total natural gas production was 19,800 MMcf for the three months ended March 31, 2014, an increase of 2,002 MMcf (11 percent) from 17,798 MMcf for the three months ended March 31, 2013; and

•

average realized natural gas price (excluding the effects of derivative activities) was $6.12 per Mcf during the three months ended March 31, 2014, an increase of 38 percent from $4.43 per Mcf during the three months ended March 31, 2013. For the three months ended March 31, 2014 and 2013, we realized approximately 129.7 percent and 126.9 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Historically, approximately 55 to 80 percent of our total natural gas revenues were derived from the value of the natural gas liquids, with the remaining portion coming from the value of the dry natural gas residue. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues historically, our realized natural gas price (excluding the effects of derivatives) has reflected a price greater than the related NYMEX natural gas price.

Production expenses. The following table provides the components of our total oil and natural gas production costs for the three months ended March 31, 2014 and 2013:


	Three Months Ended March 31,
	2014				2013
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Lease operating expenses	$	70,193	$	7.67	$	54,173	$	7.01
Taxes:
Ad valorem		5,691		0.62		5,775		0.75
Production		47,422		5.18		35,229		4.56
Workover costs		3,618		0.40		5,668		0.73

Total oil and natural gas production expenses	$	126,924	$	13.87	$	100,845	$	13.05

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

Lease operating expenses were $70.2 million ($7.67 per Boe) for the three months ended March 31, 2014, which was an increase of $16.0 million (30 percent) from $54.2 million ($7.01 per Boe) for the three months ended March 31, 2013. The increase in lease operating expenses was primarily due to increased production associated with our wells successfully drilled and completed in 2013 and 2014. The increase in lease operating expenses per Boe was primarily due to expansion of our production in areas with underdeveloped infrastructure causing a broader use of rental equipment.

Ad valorem taxes have decreased slightly due to adjustments to our rate and valuation estimates.

Production taxes per unit of production were $5.18 per Boe during the three months ended March 31, 2014, an increase of 14 percent from $4.56 per Boe during the three months ended March 31, 2013. The increase was directly related to the increase in commodity prices. Over the same period, our per Boe prices (excluding the effects of derivatives) increased 18 percent.

Workover expenses were approximately $3.6 million and $5.7 million for the three months ended March 31, 2014 and 2013, respectively. The 2014 and 2013 expenses related primarily to routine workovers in the Texas Permian and New Mexico Shelf areas performed to increase or restore production.

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the three months ended March 31, 2014 and 2013:


	Three Months Ended
	March 31,
(in thousands)	2014		2013
Geological and geophysical	$	1,616	$	13,240
Exploratory dry hole costs		19,772		91
Leasehold abandonments		3,945		4,387
Other		42		689

Total exploration and abandonments	$	25,375	$	18,407

Our geological and geophysical expense primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, mostly related to our Delaware Basin and Texas Permian areas. During the three months ended March 31, 2013, we had multiple seismic projects ongoing, which were completed during the second half of 2013. These projects were related to our increase in drilling and exploration activity in the Delaware Basin area.

Our exploratory dry hole costs during the three months ended March 31, 2014 were primarily related to (i) partial expensing of unsuccessful deeper lateral zones in our Delaware Basin area, (ii) expensing two unsuccessful wells drilled testing the outer limits of our Delaware Basin acreage and (iii) an unsuccessful horizontal lateral in the New Mexico Shelf area.

For the three months ended March 31, 2014 and 2013, we recorded approximately $3.9 million and $4.4 million of leasehold abandonments, respectively.

Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the three months ended March 31, 2014 and 2013:


	Three Months Ended March 31,
	2014				2013
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties	$	216,807	$	23.71	$	164,301	$	21.25
Depreciation of other property and equipment		4,220		0.46		3,754		0.49
Amortization of intangible assets—operating rights		365		0.04		365		0.05

Total depletion, depreciation and amortization	$	221,392	$	24.21	$	168,420	$	21.79

Oil price used to estimate proved oil reserves at period end	$	94.92			$	89.17
Natural gas price used to estimate proved natural gas reserves at period end	$	3.99			$	2.95

Depletion of proved oil and natural gas properties was $216.8 million ($23.71 per Boe) for the three months ended March 31, 2014, an increase of $52.5 million (32 percent) from $164.3 million ($21.25 per Boe) for the three months ended March 31, 2013. The increase in depletion expense was primarily due to increased production associated with new wells that were successfully drilled and completed in 2013 and 2014 and higher depletion rates per Boe. The increase in depletion expense per Boe was primarily due to (i) drilling deeper, higher cost wells in less proven areas and (ii) increasing production in our newer asset areas, such as the Delaware Basin, where we have a higher depletion rate than our legacy assets, such as the New Mexico Shelf.

An increasing amount of our drilling capital is spent drilling higher-cost horizontal wells, most of which are in areas that have not had significant drilling activity or historically been developed vertically. Generally, when transitioning to a horizontal program, (i) well costs are higher as efficiencies from optimization of drilling and completion methodologies have yet to be realized and (ii) our ability to record proved reserves is limited under the rules associated with recognizing proved reserves, in part due to the limited amount of horizontal wells in the area and the lack of historical well production performance. As a result of these factors, the change in our production amongst our assets, discussed above, and our significant horizontal drilling activities in the Delaware Basin, we have seen increases in our overall depletion rate over the past year to $23.71 per Boe for the three months ended March 31, 2014 as compared to $21.25 per Boe for the three months ended March 31, 2013. The overall depletion rate for the year ended December 31, 2013 was $22.48, while the depletion rate for the three months ended December 31, 2013 was $23.57, indicating a trend of increasing depletion rates due to the reasons discussed above.

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

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

General and administrative expenses. The following table provides components of our general and administrative expenses for the three months ended March 31, 2014 and 2013:


	Three Months Ended March 31,
	2014						2013
				Per						Per
(in thousands, except per unit amounts)	Amount			Boe			Amount			Boe
General and administrative expenses	$	41,466		$	4.53		$	40,688		$	5.26
Non-cash stock-based compensation		11,432			1.25			6,767			0.88
Less: Third-party operating fee reimbursements		(5,148	)		(0.56	)		(4,162	)		(0.54	)

Total general and administrative expenses	$	47,750		$	5.22		$	43,293		$	5.60

Total general and administrative expenses were approximately $47.8 million ($5.22 per Boe) for the three months ended March 31, 2014, an increase of $4.5 million (10 percent) from $43.3 million ($5.60 per Boe) for the three months ended March 31, 2013.

The increase in cash general and administrative expenses of approximately $0.8 million was primarily due to an increase in salary and the number of employees and related personnel expenses to handle our increased activities directly related to our increased drilling and exploration activities, reduced in part by an upward adjustment to our bonus accrual for services related to 2012 of approximately $5.9 million ($0.76 per Boe) included in 2013.

The increase in non-cash stock-based compensation of approximately $4.7 million was primarily due to (a) an increase in the number of employees to handle our increased activities directly related to our increased drilling and exploration activities, and (b) a $2.3 million ($0.30 per Boe) net benefit to stock-based compensation related to forfeitures and modifications of stock-based awards associated with two officer resignations included in 2013.

The decrease in total general and administrative expenses per Boe was primarily due to (a) increased production from our wells successfully drilled and completed in 2013 and 2014, (b) a $0.76 per Boe upward adjustment to our bonus accrual for services related to 2012 included in 2013, noted above, offset in part by (i) a $0.30 net benefit to stock-based compensation related to forfeitures and modifications of stock-based awards associated with two officer resignations included in 2013, noted above, and (ii) an increase in the number of employees and related personnel expenses to handle our increased 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 $5.1 million and $4.2 million during the three months ended March 31, 2014 and 2013, 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 period over period.

Loss on derivatives not designated as hedges. The following table sets forth the loss on derivatives not designated as hedges for the three months ended March 31, 2014 and 2013:


	Three Months Ended
	March 31,
(in thousands)	2014			2013
*Loss on derivatives not designated as hedges:*
Oil derivatives	$	(24,220	)	$	(59,017	)
Natural gas derivatives		(11,395	)		—

Total loss on derivatives not designated as hedges	$	(35,615	)	$	(59,017	)

The following table represents the Company’s cash receipts from (payments on) derivatives reported in the Company’s cash flows from investing for the three months ended March 31, 2014 and 2013:


	Three Months Ended
	March 31,
(in thousands)	2014			2013
*Cash receipts from (payments on) derivatives not designated as hedges:*
Oil derivatives	$	(9,769	)	$	6,016
Natural gas derivatives		(5,068	)		—

Total cash receipts from (payments on) derivatives not designated as hedges	$	(14,837	)	$	6,016

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 March 31, 2014 and 2013:


	Three Months Ended
	March 31,
(dollars in thousands)	2014			2013
Interest expense	$	56,135		$	52,106
Weighted average interest rate—credit facility		2.2	%		2.1	%
Weighted average interest rate—senior notes		5.9	%		6.4	%
Total weighted average interest rate		5.7	%		5.8	%
Weighted average credit facility balance	$	284,306		$	405,476
Weighted average senior notes balance		3,350,000			2,800,000

Total weighted average debt balance	$	3,634,306		$	3,205,476

The increase in weighted average debt balance for the three months ended March 31, 2014 as compared to the corresponding period in 2013 was due to capital expenditures in excess of our cash flows, primarily related to our drilling program. The increase in interest expense was due to an overall increase in the weighted average debt balance, offset in part by a lower weighted average interest rate due to our recent senior note issuances having lower interest rates than historical issuances.

Income tax provisions. We recorded an income tax expense of $55.3 million and $11.0 million for the three months ended March 31, 2014 and 2013, respectively. The effective income tax rates for the three months ended March 31, 2014 and 2013 were 37.7 percent and 38.5 percent, respectively. During the fourth quarter of 2013, we revised our estimated blended effective state rate to consider (a) New Mexico legislation passed that phases in a tax rate reduction from 7.6 percent to 5.9 percent in 2018 and (b) the apportionment factor for states in which we operate.

Income from discontinued operations, net of tax. In December 2012, we closed the sale of certain of our non-core assets for cash consideration of approximately $503.1 million. As a result of post-closing adjustments during the three months ended March 31, 2013, we made a positive adjustment to gain (loss) on disposition of assets of approximately $20.4 million. We recognized income from discontinued operations of $12.5 million for the three months ended March 31, 2013.

Capital Commitments, Capital Resources and Liquidity

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

Oil and natural gas properties. Our costs incurred on oil and natural gas properties, excluding acquisitions and asset retirement obligations, during the three months ended March 31, 2014 and 2013 totaled $534.7 million and $439.1 million, respectively. The primary reason for the differences in the costs incurred and cash flow expenditures is the timing of payments. The 2014 and 2013 expenditures were funded in part from borrowings under our credit facility.

Delaware Basin midstream agreements. On May 9, 2014, we signed an agreement, with an unrelated third party, to own 50 percent of a new midstream joint venture. The joint venture was formed to build a crude oil pipeline to transport production in the northern Delaware Basin. Our 50 percent share of the joint venture’s capital expenditures is estimated to be approximately $95.0 million. We expect the system to be operational in the second half of 2015.

Additionally, on May 9, 2014, we entered into a ten year crude petroleum dedication and transportation agreement with the joint venture. Under the terms of the agreement and subject to certain regulatory approvals, we are obligated to deliver oil production to the joint venture from a substantial portion of the properties that we currently operate in the northern Delaware Basin area, as well as oil production from future development of certain of our northern Delaware Basin acreage.

Three-year accelerated growth plan. In 2013, we announced an accelerated drilling program for the next three years which we expect will double production by 2016. By accelerating activity across our assets, we believe that we can deliver average annual organic production growth over the next three years in excess of our historical annual average while increasing oil mix and reducing leverage ratios.

We have historically attempted to fund our non-acquisition expenditures with our available cash and cash flow as adjusted from time to time; however during 2014, we plan to use our credit facility, or other alternative financing sources, to fund such expenditures in excess of our operating cash flows. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the availability of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions. In addition, under certain circumstances, we would consider increasing or reallocating our capital spending plans.

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

Acquisitions. Our expenditures for acquisitions of proved and unproved properties during the three months ended March 31, 2014 and 2013 totaled approximately $45.2 million and $29.8 million, respectively. Expenditures for unproved acquisitions included in the totals above were approximately $24.7 million and $27.9 million for the three months ended March 31, 2014 and 2013, respectively. Leasehold acreage acquisitions, included in our capital budget, comprised $10.0 million and $27.9 million of our unproved acquisitions for the three months ended March 31, 2014 and 2013, respectively.

Contractual obligations. Our contractual obligations include long-term debt, cash interest expense on debt, operating lease obligations, drilling commitments, employment agreements with executive officers, derivative liabilities and other obligations. Since December 31, 2013, the material changes in our contractual obligations included a $44.0 million increase in outstanding long-term debt, a $35.6 million decrease in cash interest expense on debt and a $20.8 million increase in our net commodity derivative liability. See Note H 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 three months ended March 31, 2014.

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

Capital resources. Our primary sources of liquidity have historically been cash flows generated from operating activities (including the cash settlements received from (paid on) derivatives not designated as hedges presented in our investing activities) and borrowings under our credit facility. Based on current commodity prices and capital costs, we believe our 2014 expected capital expenditures will exceed our 2014 cash flow, and we have funded, and expect to continue to fund, the shortfall with borrowings under our credit facility or capital markets or other financing transactions. We believe that we have adequate availability under our credit facility to fund any cash flow deficits, though we could reduce our capital spending program to remain substantially within our cash flow.

The following table summarizes our changes in cash and cash equivalents for the three months ended March 31, 2014 and 2013:


	Three Months Ended
	March 31,
(in thousands)	2014			2013
Net cash provided by operating activities	$	475,980		$	219,671
Net cash used in investing activities		(574,696	)		(402,129	)
Net cash provided by financing activities		98,716			180,552

Net decrease in cash and cash equivalents	$	—		$	(1,906	)

Cash flow from operating activities. The increase in operating cash flows during the three months ended March 31, 2014 as compared to the same period in 2013 was primarily due to (i) an increase in oil and natural gas revenues of approximately $188.9 million and (ii) approximately $91.9 million of positive variances in operating assets and liabilities; offset in part by (i) cash increases in related oil and natural gas production costs of approximately $26.1 million and (ii) a cash increase in interest expense of approximately $4.7 million.

Our net cash provided by operating activities includes an increase of $46.3 million and a reduction of $45.6 million for the three months ended March 31, 2014 and 2013, 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 three months ended March 31, 2014 and 2013, we invested $554.3 million and $419.8 million, respectively, for capital expenditures on oil and natural gas properties. Also, cash flows used in investing activities increased during the three months ended March 31, 2014 as compared to 2013 related to settlements paid on derivatives not designated as hedges of approximately $14.8 million during three months ended March 31, 2014 and receipts of approximately $6.0 million during the three months ended March 31, 2013. These expenditures were partially funded from borrowings under our credit facility.

Cash flow from financing activities. Net cash provided by financing activities was approximately $98.7 million and $180.6 million for the three months ended March 31, 2014 and 2013, respectively. These funds were primarily a result of borrowings and repayments under our credit facility. At March 31, 2014, our availability to borrow additional funds was approximately $2.2 billion based on bank commitments of $2.5 billion.

On May 9, 2014, we amended and restated our credit facility, increasing our borrowing base from $3.0 billion to $3.25 billion, but maintaining the aggregate lender commitments at $2.5 billion. The maturity date of the amended and restated credit facility is May 9, 2019. For additional information about the amended and restated credit facility, see Part II, Item 5.

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 balance outstanding on our credit facility. 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 senior unsecured debt. There are no assurances that we can access the capital markets to obtain additional funding, if needed, and at what cost and terms. We may also sell assets and issue securities in exchange for oil and natural gas assets or interests in oil and natural gas companies. Additional securities may be of a class senior to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined from time to time by our board of directors. Utilization of some of these financing sources may require approval from the lenders under our credit facility.

Liquidity. Our principal sources of short-term liquidity are cash on hand and available borrowing capacity under our credit facility. At March 31, 2014, we had $21,000 of cash on hand.

At March 31, 2014, the commitments under our credit facility were $2.5 billion, which provided us with approximately $2.2 billion of available borrowing capacity. Upon a redetermination, our $3.0 billion borrowing base could be substantially reduced. There is no assurance that our borrowing base will not be reduced, which could affect our liquidity.

Debt ratings. We receive debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”), which are subject to regular reviews. S&P’s corporate rating for us is “BB+” with a stable outlook. Moody’s corporate rating for us is “Ba2” 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 March 31, 2014 was $7.5 billion, consisting of debt of $3.7 billion and stockholders’ equity of $3.9 billion. Our debt to book capitalization was 49 percent at both March 31, 2014 and December 31, 2013. Our ratio of current assets to current liabilities was 0.61 to 1.0 at March 31, 2014 as compared to 0.69 to 1.0 at December 31, 2013.

Inflation and changes in prices. Our revenues, the value of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the three months ended March 31, 2014, we received an average of $92.35 per barrel of oil and $6.12 per Mcf of natural gas before consideration of commodity derivative contracts compared to $82.49 per barrel of oil and $4.43 per Mcf of natural gas in the three months ended March 31, 2013. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business.

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 three months ended March 31, 2014. See our disclosure of critical accounting policies in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2013, filed with the United States Securities and Exchange Commission (the “SEC”) on February 20, 2014.

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, 2013.

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 March 31, 2014, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit. We do not enter into derivative or other financial instruments for speculative or trading purposes.

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

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

We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note G 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 activities could have the effect of reducing net income and the value of our securities. An average increase in the commodity price of $10.00 per barrel of oil and $1.00 per MMBtu of natural gas from the commodity prices at March 31, 2014 would have resulted in an increase in our net liability of approximately $302.1 million.

At March 31, 2014, we had (i) oil price swaps that settle on a monthly basis covering future oil production from April 1, 2014 through June 30, 2017 and (ii) oil basis swaps covering our Midland to Cushing basis differential from April 1, 2014 to December 31, 2014. See Note G of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on our commodity derivative instruments. The average NYMEX oil price for the three months ended March 31, 2014 was $98.60 per Bbl. At May 8, 2014, the NYMEX oil price was $100.26 per Bbl.

At March 31, 2014, we had (i) natural gas price swaps that settle on a monthly basis covering future natural gas production from April 1, 2014 to December 31, 2015 and (ii) natural gas collars covering future natural gas production from April 1, 2014 to December 31, 2014. See Note G of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on our commodity derivative instruments. The average NYMEX natural gas price for the three months ended March 31, 2014 was $4.72 per MMBtu. At May 8, 2014, the NYMEX natural gas price was $4.57 per MMBtu.

A decrease in the average forward NYMEX oil prices below those at March 31, 2014, would decrease the fair value liability of our commodity derivative contracts from their recorded balance at March 31, 2014. Changes in the recorded fair value of the undesignated commodity derivative contracts are marked to market through earnings as gains or losses. The

potential decrease in our fair value liability would be recorded in earnings as a gain. However, an increase in the average forward NYMEX oil and natural gas prices above those at March 31, 2014, would increase the fair value liability of our commodity derivative contracts from their recorded balance at March 31, 2014. The potential increase in our fair value liability 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 three months ended March 31, 2014, to which we were a party. See Note G of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the three months ended March 31, 2014:


	Commodity Derivative
	Instruments
(in thousands)	Net Assets (Liabilities) (a)
Fair value of contracts outstanding at December 31, 2013	$	(66,233	)
Changes in fair values (b)		(35,615	)
Contract maturities		14,837

Fair value of contracts outstanding at March 31, 2014	$	(87,011	)

(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.

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 available commitments.

We had total indebtedness of $294.7 million outstanding under our credit facility at March 31, 2014. The impact of a one percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $2.9 million.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at March 31, 2014 at the reasonable assurance level.

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

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

We are 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 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, 2013, 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, 2013. The risks described in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

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


Period	Total number of shares withheld (a)		Average price per share		Total number of shares purchased as part of publicly announced plans		Maximum number of shares that may yet be purchased under the plan
January 1, 2014 - January 31, 2014		9,146	$	104.18		—
February 1, 2014 - February 28, 2014		24,146	$	115.78		—
March 1, 2014 - March 31, 2014		—	$	—		—

(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.

Item 5. Other Information

Second Amended and Restated Credit Agreement

On May 9, 2014, we entered into a Second Amended and Restated Credit Agreement (the “Credit Agreement”) with JPMorgan Chase Bank, N.A. as administrative agent, and the other lenders party thereto. The Credit Agreement amends and restates the terms of our existing Amended and Restated Credit Agreement, as amended, dated as of July 31, 2008, with JPMorgan Chase Bank, N.A., as administrative agent. Terms used herein and not defined have the respective meanings given to such terms in the Credit Agreement.

The Credit Agreement is a senior secured borrowing base revolving credit facility in an aggregate maximum principal amount of $4 billion, with an initial borrowing base of $3.25 billion, with aggregate lender commitments at $2.5 billion, guaranteed on a senior basis by all our subsidiaries (to be redetermined on a periodic basis in accordance with the terms of the Credit Agreement and subject to the Investment Grade Period, discussed below). Additionally, under the Credit Agreement, letters of credit are available to us in an aggregate stated amount not to exceed $100 million and swingline loans are available in amount not to exceed $50 million, each subject to the available commitments under the Credit Agreement.

The Credit Agreement has a maturity date of May 9, 2019.

The revolving loans bear interest at a rate equal to either (i) for ABR Loans, the ABR plus an Applicable Margin ranging from 0.25 percent to 1.25 percent during a non-Investment Grade Period and from 0.125 percent to 0.75 percent during an Investment Grade Period, or (ii) for LIBOR Loans, the LIBOR Rate plus the Applicable Margin ranging from 1.25 percent to 2.25 percent during a non-Investment Grade Period and from 1.125 percent to 1.75 percent during an Investment Grade Period, in each such case, from the date of borrowing until maturity or repayment.

Under the Credit Agreement, we are obligated to comply with certain financial covenants requiring us to maintain (i) a ratio of Consolidated Total Debt to Consolidated EBITDAX less than 4.25 to 1.00, (ii) a ratio of Consolidated Current Assets to Consolidated Current Liabilities greater than 1.00 to 1.00, and (iii) during any Investment Grade Period on which we do not have both (1) an unsecured rating from Moody’s of Baa3 or better and (2) an unsecured rating from S&P of BBB- or better, a ratio of the PV-9 of our oil and gas properties to Consolidated Total Debt greater than 1.50 to 1.00.

In addition, the Credit Agreement contains various covenants that limit, among other things, our ability to: incur indebtedness; grant liens; issue preferred stock; engage in certain mergers, consolidations, liquidations and dissolutions; engage in certain sales of assets; make distributions and dividends; enter into transactions with affiliates; and make certain acquisitions and investments.

If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the credit facilities and exercise other rights and remedies. An event of default includes, among other things: nonpayment of principle when due; nonpayment of interest, fees or other amounts (subject to a five-day grace period); material inaccuracy of representations and warranties; violation of covenants; cross-default in excess of $125 million; bankruptcy events; certain ERISA events; judgments in excess of $125 million; and a change in control.

Subject to the Investment Grade Period described in the paragraph below, the Credit Agreement will be secured by sufficient mortgages such that the ratio of present value of mortgaged properties to the total maximum outstanding exposure under the facility at such time is at least 1.75 to 1.0 In addition, the Credit Agreement will be secured by the pledge of the equity interests in each of the subsidiary guarantors of the Company, and a security interest granted in all of the assets of the Company and its subsidiary guarantors (all such security subject to certain carve outs in the Credit Agreement).

If we receive an unsecured rating from at least one of Moody’s or S&P of Baa3 or better or BBB- or better, as applicable, then at our election, we may enter into an investment grade period under the Credit Agreement (the “Investment Grade Period”). During the Investment Grade Period, all security interests shall be released. Additionally, during an Investment Grade Period, the Applicable Margin will shift such that pricing will be based on ratings, and the amount drawn will be based solely on the outstanding commitments of the lenders and not limited by the Borrowing Base.

The foregoing description of the Credit Agreement is a summary only and is qualified in its entirety by the terms of the Credit Agreement, a copy of which is attached as Exhibit 10.1 to this Quarterly Report on Form 10-Q and incorporated herein by reference.

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).

10.1 (a)		Second Amended and Restated Credit Agreement, dated as of May 9, 2014, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent.

10.2 **		Form of Director and Officer Indemnification Agreement between Concho Resources Inc. and each Messrs. Surma and Harper (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 24, 2014, and incorporated herein by reference).

10.3 **		Employment Agreement dated March 19, 2014, between Concho Resources Inc. and Jack F. Harper (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on March 24, 2014, 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.

**	Management contract or compensatory plan or agreement

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: May 12, 2014		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 and Chief Financial Officer
			(Principal Financial Officer)

		By	/s/ Brenda R. Schroer
			Brenda R. Schroer
			Vice President and Chief Accounting Officer
			(Principal Accounting Officer)

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).

10.1 (a)		Second Amended and Restated Credit Agreement, dated as of May 9, 2014, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent.

10.2 **		Form of Director and Officer Indemnification Agreement between Concho Resources Inc. and each Messrs. Surma and Harper (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 24, 2014, and incorporated herein by reference).

10.3 **		Employment Agreement dated March 19, 2014, between Concho Resources Inc. and Jack F. Harper (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on March 24, 2014, 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.

**	Management contract or compensatory plan or agreement