Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended June 30, 2019



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

For the transition period from to a

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 incorporation or organization)		(I.R.S. Employer 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)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.001 per share	CXO	New York Stock Exchange

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes þ No ¨

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



Large accelerated filer	þ	Accelerated filer	☐

Non-accelerated filer	☐	Smaller reporting company	☐

Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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 þ

Number of shares of the registrant’s common stock outstanding at July 30, 2019: 201,078,813 shares

Table of Contents

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	32

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	47

	Item 4. Controls and Procedures	49

PART II – OTHER INFORMATION:		50

	Item 1. Legal Proceedings	50

	Item 1A. Risk Factors	50

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	51

	Item 6. Exhibits	52

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements and information 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, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our future financial position, operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims, disputes and derivative activities. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “will,” “goal” or other words that convey future events, expectations or possible outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events and their potential effect on us. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by any forward-looking statements. These forward-looking statements speak only as of the date of this 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, whether as a result of new information, future events or otherwise, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Part I, Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2018, as well as those factors summarized below:


•	declines in, the sustained depression of, or increased volatility in the prices we receive for our oil and natural gas, or increases in the differential between index oil or natural gas prices and prices received;


•	the effects of government regulation, permitting and other legal requirements, including new legislation or regulation related to hydraulic fracturing, climate change or derivatives reform;


•	competition in the oil and natural gas industry;


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


•	drilling, completion and operating risks, including our ability to efficiently execute large-scale project development as we could experience delays, curtailments and other adverse impacts associated with a high concentration of activity;


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


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


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


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


•	evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions;


•	risks related to ongoing expansion of our business, including the recruitment and retention of qualified personnel in the Permian Basin;


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


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


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


•	risks associated with acquisitions such as increased expenses and integration efforts, failure to realize the expected benefits of the transaction and liabilities associated with acquired properties or businesses;


•	the impact of current and potential changes to federal or state tax rules and regulations;


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


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


•	the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our Credit Facility, as defined herein;


•	the impact of potential changes in our credit ratings; and


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

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 the 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.

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PART I – FINANCIAL INFORMATION


Item 1.	Consolidated Financial Statements (Unaudited)



Consolidated Balance Sheets at June 30, 2019 and December 31, 2018	1

Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2019 and 2018	2

Consolidated Statements of Stockholders’ Equity for the Three and Six Months Ended June 30, 2019 and 2018	3

Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2019 and 2018	5

Condensed Notes to Consolidated Financial Statements	6

iii

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Concho Resources Inc.

Consolidated Balance Sheets

Unaudited



(in millions, except share and per share amounts)	June 30, 2019			December 31, 2018
Assets
Current assets:
Cash and cash equivalents	$	—		$	—
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas	460			466
Joint operations and other	301			365
Inventory	33			35
Derivative instruments	12			484
Prepaid costs and other	54			59
Total current assets	860			1,409
Property and equipment:
Oil and natural gas properties, successful efforts method	33,321			31,706
Accumulated depletion and depreciation	(11,479		)	(9,701		)
Total oil and natural gas properties, net	21,842			22,005
Other property and equipment, net	374			308
Total property and equipment, net	22,216			22,313
Deferred loan costs, net	9			10
Goodwill	2,222			2,224
Intangible assets, net	18			19
Noncurrent derivative instruments	29			211
Other assets	124			108
Total assets	$	25,478		$	26,294
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable - trade	$	55		$	50
Book overdrafts	143			159
Revenue payable	255			253
Accrued drilling costs	506			574
Derivative instruments	126			—
Other current liabilities	318			320
Total current liabilities	1,403			1,356
Long-term debt	4,350			4,194
Deferred income taxes	1,561			1,808
Noncurrent derivative instruments	12			—
Asset retirement obligations and other long-term liabilities	193			168
Commitments and contingencies (Note 9)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 201,764,616 and 201,288,884 shares issued at June 30, 2019 and December 31, 2018, respectively	—			—
Additional paid-in capital	14,820			14,773
Retained earnings	3,284			4,126
Treasury stock, at cost; 1,166,326 and 1,031,655 shares at June 30, 2019 and December 31, 2018, respectively	(145		)	(131		)
Total stockholders’ equity	17,959			18,768
Total liabilities and stockholders’ equity	$	25,478		$	26,294

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

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Concho Resources Inc.

Consolidated Statements of Operations

Unaudited



	Three Months Ended June 30,						Six Months Ended June 30,
(in millions, except per share amounts)	2019			2018			2019			2018
Operating revenues:
Oil sales	$	1,049		$	795		$	1,984		$	1,588
Natural gas sales	78			150			247			304
Total operating revenues	1,127			945			2,231			1,892
Operating costs and expenses:
Oil and natural gas production	188			130			362			260
Production and ad valorem taxes	84			70			170			140
Gathering, processing and transportation	22			9			48			20
Exploration and abandonments	17			8			64			26
Depreciation, depletion and amortization	478			310			943			627
Accretion of discount on asset retirement obligations	2			2			5			4
Impairments of long-lived assets	868			—			868			—
General and administrative (including non-cash stock-based compensation of $23 and $18 for the three months ended June 30, 2019 and 2018, respectively, and $47 and $35 for the six months ended June 30, 2019 and 2018, respectively)	88			72			179			137
(Gain) loss on derivatives	(217		)	133			842			168
(Gain) loss on disposition of assets, net	1			(1		)	—			(724		)
Transaction costs	1			9			1			16
Total operating costs and expenses	1,532			742			3,482			674
Income (loss) from operations	(405		)	203			(1,251		)	1,218
Other income (expense):
Interest expense	(48		)	(27		)	(95		)	(57		)
Other, net	303			1			307			105
Total other income (expense)	255			(26		)	212			48
Income (loss) before income taxes	(150		)	177			(1,039		)	1,266
Income tax (expense) benefit	53			(40		)	247			(294		)
Net income (loss)	$	(97	)	$	137		$	(792	)	$	972
Earnings per share:
Basic net income (loss)	$	(0.48	)	$	0.92		$	(3.98	)	$	6.52
Diluted net income (loss)	$	(0.48	)	$	0.92		$	(3.98	)	$	6.50

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

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Concho Resources Inc.

Consolidated Statements of Stockholders’ Equity

Unaudited



	Three Months Ended June 30, 2019
	Common Stock Issued				Additional Paid-in Capital		Retained Earnings			Treasury Stock				Total Stockholders’ Equity
(in millions, except share data)	Shares		Amount		Additional Paid-in Capital		Retained Earnings			Shares	Amount			Total Stockholders’ Equity
	(in thousands)									(in thousands)
BALANCE AT MARCH 31, 2019	201,755		$	—	$	14,797	$	3,406		1,156	$	(144	)	$	18,059
Net loss	—		—		—		(97		)	—	—			(97		)
Common stock dividends ($0.125 per share)	—		—		—		(25		)	—	—			(25		)
Grants of restricted stock	26		—		—		—			—	—			—
Performance unit share conversion	—		—		—		—			—	—			—
Cancellation of restricted stock	(16	)	—		—		—			—	—			—
Stock-based compensation	—		—		23		—			—	—			23
Purchase of treasury stock	—		—		—		—			10	(1		)	(1		)
BALANCE AT JUNE 30, 2019	201,765		$	—	$	14,820	$	3,284		1,166	$	(145	)	$	17,959



	Six Months Ended June 30, 2019
	Common Stock Issued				Additional Paid-in Capital		Retained Earnings			Treasury Stock				Total Stockholders’ Equity
(in millions, except share data)	Shares		Amount		Additional Paid-in Capital		Retained Earnings			Shares	Amount			Total Stockholders’ Equity
	(in thousands)									(in thousands)
BALANCE AT DECEMBER 31, 2018	201,289		$	—	$	14,773	$	4,126		1,032	$	(131	)	$	18,768
Net loss	—		—		—		(792		)	—	—			(792		)
Common stock dividends ($0.25 per share)	—		—		—		(50		)	—	—			(50		)
Grants of restricted stock	261		—		—		—			—	—			—
Performance unit share conversion	246		—		—		—			—	—			—
Cancellation of restricted stock	(31	)	—		—		—			—	—			—
Stock-based compensation	—		—		47		—			—	—			47
Purchase of treasury stock	—		—		—		—			134	(14		)	(14		)
BALANCE AT JUNE 30, 2019	201,765		$	—	$	14,820	$	3,284		1,166	$	(145	)	$	17,959

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

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Concho Resources Inc.

Consolidated Statements of Stockholders’ Equity

Unaudited



	Three Months Ended June 30, 2018
	Common Stock Issued				Additional Paid-in Capital		Retained Earnings		Treasury Stock				Total Stockholders’ Equity
(in millions, except share data)	Shares		Amount		Additional Paid-in Capital		Retained Earnings		Shares	Amount			Total Stockholders’ Equity
	(in thousands)								(in thousands)
BALANCE AT MARCH 31, 2018	149,870		$	—	$	7,159	$	2,675	800	$	(96	)	$	9,738
Net income	—		—		—		137		—	—			137
Grants of restricted stock	335		—		—		—		—	—			—
Performance unit share conversion	—		—		—		—		—	—			—
Cancellation of restricted stock	(10	)	—		—		—		—	—			—
Stock-based compensation	—		—		18		—		—	—			18
Purchase of treasury stock	—		—		—		—		13	(2		)	(2		)
BALANCE AT JUNE 30, 2018	150,195		$	—	$	7,177	$	2,812	813	$	(98	)	$	9,891



	Six Months Ended June 30, 2018
	Common Stock Issued				Additional Paid-in Capital		Retained Earnings		Treasury Stock				Total Stockholders’ Equity
(in millions, except share data)	Shares		Amount		Additional Paid-in Capital		Retained Earnings		Shares	Amount			Total Stockholders’ Equity
	(in thousands)								(in thousands)
BALANCE AT DECEMBER 31, 2017	149,325		$	—	$	7,142	$	1,840	598	$	(67	)	$	8,915
Net income	—		—		—		972		—	—			972
Grants of restricted stock	447		—		—		—		—	—			—
Performance unit share conversion	446		—		—		—		—	—			—
Cancellation of restricted stock	(23	)	—		—		—		—	—			—
Stock-based compensation	—		—		35		—		—	—			35
Purchase of treasury stock	—		—		—		—		215	(31		)	(31		)
BALANCE AT JUNE 30, 2018	150,195		$	—	$	7,177	$	2,812	813	$	(98	)	$	9,891

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

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Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited



	Six Months Ended June 30,
(in millions)	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(792	)	$	972
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	943			627
Accretion of discount on asset retirement obligations	5			4
Impairments of long-lived assets	868			—
Exploration and abandonments	51			14
Non-cash stock-based compensation expense	47			35
Deferred income taxes	(247		)	294
Net gain on disposition of assets and other non-operating items	(288		)	(724		)
Loss on derivatives	842			168
Net settlements paid on derivatives	(50		)	(194		)
Other	(10		)	(95		)
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable	33			(56		)
Prepaid costs and other	4			(22		)
Inventory	1			(3		)
Accounts payable	5			5
Revenue payable	5			43
Other current liabilities	(15		)	22
Net cash provided by operating activities	1,402			1,090
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and natural gas properties	(1,726		)	(941		)
Acquisitions of oil and natural gas properties	(14		)	(19		)
Additions to property, equipment and other assets	(41		)	(11		)
Proceeds from the disposition of assets	311			261
Direct transaction costs for asset acquisitions and dispositions	(3		)	(3		)
Distribution from equity method investment	—			148
Net cash used in investing activities	(1,473		)	(565		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	2,060			1,222
Payments on credit facility	(1,905		)	(1,544		)
Payments for loan costs	—			(1		)
Payment of common stock dividends	(50		)	—
Purchases of treasury stock	(14		)	(31		)
Decrease in book overdrafts	(16		)	(116		)
Other	(4		)	—
Net cash provided by (used in) financing activities	71			(470		)
Net increase in cash and cash equivalents	—			55
Cash and cash equivalents at beginning of period	—			—
Cash and cash equivalents at end of period	$	—		$	55

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

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

Unaudited

Note 1. Organization and nature of operations

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

Note 2. Basis of presentation and summary of significant accounting policies

A complete discussion of the Company’s significant accounting policies is included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 Form 10-K”).

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

Reclassifications. Certain prior period amounts have been reclassified to conform to the 2019 presentation. These reclassifications had no impact on net income (loss), total assets, liabilities and stockholders’ equity or total cash flows.

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 oil and natural gas 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, commodity price outlooks and prevailing market rates of other sources of income and costs. Other significant estimates include, but are not limited to, asset retirement obligations, goodwill, fair value of stock-based compensation, fair value of business combinations, fair value of nonmonetary transactions, fair value of derivative financial instruments 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, 2018 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 notes to the consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in the Company’s 2018 Form 10-K.

Equity method investments. The Company accounts for its equity method investments under the equity method of accounting and includes the investment balance in other assets on the consolidated balance sheets. Gains and losses incurred from the Company’s equity investments are recorded in other income (expense) on the consolidated statements of operations. The Company recorded net income of $15 million for the three months ended June 30, 2019, and $15 million and $5 million for the six months ended June 30, 2019 and 2018, respectively.

Until May 2019, the Company owned a 23.75 percent membership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that owned and operated Oryx I, a crude oil gathering and transportation system in the Delaware Basin (“Oryx I”). In February 2018, Oryx obtained a term loan of $800 million. The proceeds were used in part to fund a cash distribution to its equity holders, of which the Company received a distribution of approximately $157 million. Of this amount, approximately $54 million fully offset the Company’s net investment in Oryx. The net investment of $54 million included $45 million of Company's contributions made to Oryx and $9 million of equity income. The remaining distribution of approximately $103 million was recorded in other income (expense) on the Company’s consolidated statement of operations. In May 2019, Oryx completed the sale of 100 percent of its equity interests in Oryx I. The Company received $289 million, net of closing costs, in connection with the sale of Oryx I.

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

Unaudited

In April 2019, the Company entered into a midstream joint venture, Beta Holding Company, LLC (“Beta Holding”), to construct a pipeline to gather and transport oil production in the Midland Basin. The Company also entered into a ten-year dedication agreement with an affiliate of Beta Holding to transport the Company’s oil production in the Midland Basin. The Company owns a 50 percent membership interest in Beta Holding.

The Company owns a membership interest in WaterBridge Operating LLC (“WaterBridge”), an entity that operates and manages various water infrastructure assets located in the Permian Basin. The Company also has a water management services agreement with WaterBridge.

Litigation contingencies. The Company is a party to proceedings and claims incidental to its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. The amount of any resulting losses may differ from these estimates. An accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable. See Note 9 for additional information.

Revenue recognition. The Company recognizes revenues from the sales of oil and natural gas to its customers and presents them disaggregated on the Company’s consolidated statements of operations. All revenues are recognized in the geographical region of the Permian Basin.

The Company enters into contracts with customers to sell its oil and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with Customers,” (“ASC 606”). Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. At June 30, 2019 and December 31, 2018, the Company had receivables related to contracts with customers of $460 million and $466 million, respectively.

Oil Contracts. The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing which is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred after the transfer of control of the oil, the differentials are included in oil sales on the consolidated statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in gathering, processing and transportation on the Company’s consolidated statements of operations and are accounted for as costs incurred directly and not netted from transaction price.

Natural Gas Contracts. The majority of the Company’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. The natural gas is sold under (i) percentage of proceeds processing contracts, (ii) fee-based contracts or (iii) a hybrid of percentage of proceeds and fee-based contracts. Under the majority of the Company’s contracts, the purchaser gathers the natural gas in the field where it is produced and transports it via pipeline to natural gas processing plants where natural gas liquid products are extracted. The natural gas liquid products and remaining residue gas are then sold by the purchaser. Under the percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, the Company receives a percentage of the value for the extracted liquids and the residue gas. Under the fee-based contracts, the Company receives natural gas liquids and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those activities, revenue is recognized on a gross basis, and the related costs are classified in gathering, processing and transportation on the Company’s consolidated statements of operations.

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and records such reimbursements as reductions to general and administrative

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

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expense. Such fees totaled $4 million and $5 million for the three months ended June 30, 2019 and 2018, respectively, and $8 million and $9 million for the six months ended June 30, 2019 and 2018, respectively.

Recently adopted accounting pronouncements. In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, “Leases (Topic 842)” (“ASU 2016-02”), which requires all leases with a term greater than one year to be recognized on the consolidated balance sheet while maintaining similar classifications for finance and operating leases. Lease expense recognition on the consolidated statements of operations was effectively unchanged. The Company adopted this guidance on January 1, 2019. The Company made policy elections not to capitalize short-term leases for all asset classes and not to separate non-lease components from lease components for all asset classes except for vehicles. The Company also did not elect the package of practical expedients that allowed for certain considerations under the original “Leases (Topic 840)” accounting standard (“Topic 840”) to be carried forward upon adoption of ASU 2016-02.

In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient not to evaluate land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under Topic 840. The Company enters into land easements on a routine basis as part of its ongoing operations and has many such agreements currently in place; however, the Company did not account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, the Company elected this practical expedient, which became effective upon the date of adoption of ASU 2016-02. The Company will assess any new land easements to determine whether the arrangement should be accounted for as a lease. In July 2018, the FASB issued ASU No. 2018-11, “Targeted Improvements,” which provides a transition election not to restate comparative periods for the effects of applying the new lease standard. This transition election permits entities to change the date of initial application to the beginning of the year of adoption and to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings. The Company elected this transition approach, however the cumulative impact of adoption in the opening balance of retained earnings as of January 1, 2019 was zero.

The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field equipment and drilling rigs. Upon adoption, the Company recognized $35 million of right-of-use assets, of which $19 million and $16 million relate to the Company’s operating and finance leases, respectively, and $37 million of associated lease liabilities. See Note 9 for additional disclosures of the Company’s leases.

In August 2018, the Securities and Exchange Commission (“SEC”) issued a final rule that amends certain of its disclosure requirements that have become redundant, duplicative, overlapping, outdated or superseded, in light of other disclosure requirements, U.S. GAAP or changes in the information environment. The amendments are intended to facilitate the disclosure of information to investors and simplify compliance without significantly altering the total mix of information provided to investors. The final rule amends numerous SEC rules, items and forms covering a diverse group of topics, including, but not limited to, changes in stockholders’ equity. The final rule extends the annual disclosure requirement in SEC Regulation S-X, Rule 3-04, of presenting changes in stockholders’ equity to interim periods. Registrants are required to analyze changes in stockholders’ equity in the form of a reconciliation for the current quarter and year-to-date interim periods and comparative periods in the prior year. As a result, the Company updated its presentation of the consolidated statements of stockholders’ equity to include comparative periods in the prior year. In addition, the final rule requires the presentation of dividends per share to be disclosed in the statement of stockholders’ equity.

New accounting pronouncements issued but not yet adopted. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (“Topic 326”), which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. In November 2018, the FASB issued ASU No. 2018-19, “Codification Improvements to Topic 326, Financial Instruments–Credit Losses,” which makes amendments to clarify the scope of the guidance, including the amendment clarifying that receivables arising from operating leases are not within the scope of Topic 326. This guidance is effective for fiscal years beginning after December 15, 2019, and early adoption is allowed as early as fiscal years beginning after December 15, 2018. The Company does not believe this new guidance will have a material impact on its consolidated financial statements.

In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606” (“ASU 2018-18”), which, among other things, clarifies that (i) certain transactions between collaborative arrangement participants should be accounted for as revenue under Topic 606 when the collaborative arrangement participant is a customer in the context of a unit of account, (ii) adds unit-of-account guidance in Topic 808 to align with the guidance in Topic 606 and (iii) requires that in a transaction with a collaborative arrangement participant that is not directly related to sales to third parties, presenting the transaction together with revenue recognized under Topic 606 is precluded if the collaborative

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

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arrangement participant is not a customer. ASU 2018-18 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years and early adoption is permitted. The amendments in this update should be applied retrospectively to the date of initial application of Topic 606. An entity should recognize the cumulative effect of initially applying the amendments as an adjustment to the opening balance of retained earnings of the later of the earliest annual period presented and the annual period that includes the date of the entity’s initial application of Topic 606. The Company does not believe this new guidance will have a material impact on its consolidated financial statements.

Note 3. RSP Acquisition

On July 19, 2018, the Company completed the acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”) for approximately $7.5 billion.

Purchase price allocation. The RSP Acquisition has been accounted for as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price of RSP to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Any value assigned to goodwill is not deductible for income tax purposes.

The following table sets forth the Company’s final purchase price allocation:



(in millions)
Total purchase price	$	7,549

Fair value of liabilities assumed:
Accounts payable – trade	$	48
Accrued drilling costs	79
Current derivative instruments	10
Other current liabilities	116
Long-term debt	1,758
Deferred income taxes	515
Asset retirement obligations	20
Noncurrent derivative instruments	5
Total liabilities assumed	$	2,551

Total purchase price plus liabilities assumed	$	10,100

Fair value of assets acquired:
Accounts receivable	$	194
Current derivative instruments	36
Other current assets	21
Proved oil and natural gas properties	4,055
Unproved oil and natural gas properties	3,565
Other property and equipment	5
Noncurrent derivative instruments	2
Implied goodwill	2,222
Total assets acquired	$	10,100

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

Unaudited

Pro forma data. The following unaudited pro forma combined condensed financial data for the three and six months ended June 30, 2018 was derived from the historical financial statements of the Company giving effect to the RSP Acquisition as if it had occurred on January 1, 2017. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for RSP’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert RSP’s outstanding shares of common stock and equity awards as of the closing date of the RSP Acquisition, (ii) the depletion of RSP’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments.

The pro forma results of operations do not include any cost savings or other synergies that may result from the RSP Acquisition. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the period. The pro forma combined condensed financial data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the RSP Acquisition taken place on January 1, 2017 and is not intended to be a projection of future results.



(in millions, except per share amounts)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Operating revenues	$	1,262	$	2,488
Net income	$	238	$	1,169
Earnings per share:
Basic net income	$	1.19	$	5.85
Diluted net income	$	1.19	$	5.83

Note 4. Other acquisitions, divestitures and nonmonetary transactions

During the six months ended June 30, 2018, the Company closed the following transactions:

February 2018 acquisition and divestiture. In February 2018, the Company closed an acquisition treated as a business combination where it received producing wells along with approximately 21,000 net acres, primarily located in the Midland Basin. As consideration for the non-cash acquisition, the Company divested of certain producing wells and approximately 34,000 net acres located primarily in the northern portion of the Delaware Basin. The business acquired was valued at approximately $755 million as compared to the historical book value of the divested assets of approximately $180 million, which resulted in a non-cash gain of approximately $575 million, included in gain on disposition of assets, net on the Company’s consolidated statement of operations for the six months ended June 30, 2018.

Delaware Basin divestitures. In January 2018, the Company closed on two asset divestitures of certain non-core assets in Reeves and Ward Counties, Texas, with combined proceeds of approximately $280 million. After direct transaction costs, the Company recorded a pre-tax gain of approximately $134 million, which is included in gain on disposition of assets, net on its consolidated statement of operations for the six months ended June 30, 2018. The assets divested included proved and unproved oil and natural gas properties on approximately 20,000 net acres.

Nonmonetary transactions. During the six months ended June 30, 2018, the Company completed multiple nonmonetary transactions. These transactions included exchanges of both proved and unproved oil and natural gas properties. Certain of these transactions were accounted for at fair value and, as a result, the Company recorded pre-tax gains of approximately $15 million, included in gain on disposition of assets, net on the Company’s consolidated statement of operations for the six months ended June 30, 2018.

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

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Note 5. Stock incentive plan

On May 16, 2019, the Company’s stockholders approved and adopted the Company’s 2019 Stock Incentive Plan (“the Plan”), which, among other things, increased the total shares authorized for issuance from 10.5 million to 15 million. The Plan provides for granting stock options, restricted stock awards and performance unit awards to directors, officers and employees of the Company. The restricted stock awards vest over a period ranging from one to ten years. The holders of unvested restricted stock awards have voting rights and the right to receive dividends.

In January 2019, the Company granted 212,947 performance unit awards. Included in this grant were 38,952 performance unit awards granted to certain officers, of which 19,476 have a three-year performance period and 19,476 have a five-year performance period. For these 38,952 performance unit awards, at the end of each performance period, each of these performance unit awards will convert into a restricted stock award with the number of shares determined based upon performance criteria, which will then vest at a rate of 20 percent per year commencing on the sixth anniversary of the grant date. All other performance unit awards granted during 2019 will vest at the end of a three-year performance period.

Shares issued as a result of awards granted under the Plan are generally new common shares.

A summary of the Company’s restricted stock shares and performance unit activity under the Plan for the six months ended June 30, 2019 is presented below:



	Restricted Stock Shares			Performance Units
Outstanding at December 31, 2018	1,364,699			218,391
Awards granted (a)	260,537			212,947		(b)
Awards canceled / forfeited	(31,119		)	—
Lapse of restrictions	(349,594		)	—
Outstanding at June 30, 2019	1,244,523			431,338

(a) Weighted average grant date fair value per share/unit	$	105.59		$	144.03
(b) Includes 38,952 performance unit awards granted to certain officers in January 2019 that may convert into shares of restricted stock awards at the end of each performance period that will be subject to additional vesting conditions.

The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at June 30, 2019:



(in millions)
Remaining 2019	$	37
2020	48
2021	23
2022	4
2023	2
2024	1
Thereafter	2
Total	$	117

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

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Note 6. Disclosures about fair value measurements

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


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

Level 2:

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

Level 3:

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

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

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 June 30, 2019 and December 31, 2018:



(in millions)	June 30, 2019				December 31, 2018
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value

Assets:
Derivative instruments	$	41	$	41	$	695	$	695

Liabilities:
Derivative instruments	$	138	$	138	$	—	$	—
Credit facility	$	397	$	397	$	242	$	242
$600 million 4.375% senior notes due 2025 (a)	$	594	$	624	$	594	$	591
$1,000 million 3.75% senior notes due 2027 (a)	$	989	$	1,033	$	989	$	939
$1,000 million 4.3% senior notes due 2028 (a)	$	989	$	1,081	$	988	$	980
$800 million 4.875% senior notes due 2047 (a)	$	789	$	896	$	789	$	761
$600 million 4.85% senior notes due 2048 (a)	$	592	$	675	$	592	$	573

(a) The carrying value includes associated deferred loan costs and any discount.

Credit facility. The carrying amount of the Company’s credit facility, as amended and restated (the “Credit Facility”), approximates its fair value, as the applicable interest rates are variable and reflective of market rates.

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.

Other financial assets and liabilities. The Company has other financial instruments consisting primarily of receivables, payables and other current assets and liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

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Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at June 30, 2019 and December 31, 2018. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.



June 30, 2019
(in millions)	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Fair Value			Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
Assets:
Current:
Commodity derivatives	$	—	$	109		$	—	$	109		$	(97	)	$	12
Noncurrent:
Commodity derivatives	—		58			—		58			(29		)	29

Liabilities:
Current:
Commodity derivatives	—		(223		)	—		(223		)	97			(126		)
Noncurrent:
Commodity derivatives	—		(41		)	—		(41		)	29			(12		)

Net derivative instruments	$	—	$	(97	)	$	—	$	(97	)	$	—		$	(97	)

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

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December 31, 2018
	Fair Value Measurements Using
(in millions)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Fair Value			Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
Assets:
Current:
Commodity derivatives	$	—	$	543		$	—	$	543		$	(59	)	$	484
Noncurrent:
Commodity derivatives	—		243			—		243			(32		)	211

Liabilities:
Current:
Commodity derivatives	—		(59		)	—		(59		)	59			—
Noncurrent:
Commodity derivatives	—		(32		)	—		(32		)	32			—

Net derivative instruments	$	—	$	695		$	—	$	695		$	—		$	695

Concentrations of credit risk. At June 30, 2019, the Company’s primary concentrations of credit risk are the risk of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations.

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

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

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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. The Company reviews its oil and natural gas properties by depletion base. 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. If the estimated undiscounted future net cash flows are less than the carrying amount of the Company’s assets, it 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 calculates the expected undiscounted future net cash flows of its long-lived assets and their integrated assets using management’s assumptions and expectations of (i) commodity prices, which are based on the NYMEX strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, and (vii) prevailing market rates of income and expenses from integrated assets. At June 30, 2019, the Company’s estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a 2019 price of $58.32 per barrel of oil decreasing to a 2022 price of $53.58 then rising to a 2026 price of $54.47 per barrel of oil. Natural gas prices ranged from a 2019 price of $2.38 per Mcf of natural gas increasing to a 2026 price of $2.99 per Mcf. Both oil and natural gas commodity prices for this purpose were held flat after 2026.

The Company calculates the estimated fair values of its long-lived assets and their integrated assets using a discounted future cash flow model. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, and (v) a market-based weighted average cost of capital. The Company utilized a combination of the NYMEX strip pricing and consensus pricing, adjusted for differentials, to value the reserves. These are classified as Level 3 fair value assumptions.

At June 30, 2019, the carrying amount of the proved properties of the Company's Yeso field exceeded the expected undiscounted future net cash flows resulting in a non-cash charge against earnings of $868 million. The non-cash charge represented the amount by which the carrying amount exceeded the estimated fair value of the assets and was attributable primarily to certain downward adjustments to our economically recoverable proved oil and natural gas reserves. At June 30, 2019, the Company's estimate of commodity prices for purposes of determining discounted future cash flows ranged from a 2019 price of $58.32 per barrel of oil increasing to a 2026 price of $62.06 per barrel of oil. Natural gas prices ranged from a 2019 price of $2.38 per Mcf of natural gas increasing to a 2026 price of $3.00 per Mcf of natural gas. These prices were then adjusted for location and quality differentials. Both oil and natural gas commodity prices for this purpose were inflated by two percent each year after 2026. The expected future net cash flows were discounted using an annual rate of 10 percent.

It is reasonably possible that the estimate of undiscounted future net cash flows of the Company’s long-lived assets may change in the future resulting in the need to further impair carrying values. The primary factors that may affect estimates of future cash flows are (i) commodity prices including differentials, (ii) increases or decreases in production and capital costs, (iii) future reserve volume adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) results of future drilling activities and (v) changes in income and expenses from integrated assets.

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

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Note 7. Derivative financial instruments

The Company uses derivative financial instruments to manage its exposure to commodity price fluctuations. Commodity derivative instruments are used to (i) reduce the effect of the volatility of price changes on the oil and natural gas the Company produces and sells, (ii) support the Company’s capital budget and expenditure plans and (iii) support the economics associated with acquisitions. The Company does not enter into derivative financial instruments for speculative or trading purposes. The Company also enters into fixed-price forward physical power purchase contracts to manage the volatility of the price of power needed for ongoing operations. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these physical contracts are not expected to be net cash settled, the Company has elected normal purchase or normal sale treatment and records these contracts at cost.

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 consolidated statements of operations as they occur.

The following table summarizes the amounts reported in earnings related to the commodity derivative instruments for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,					Six Months Ended June 30,
(in millions)	2019		2018			2019			2018
Gain (loss) on derivatives:
Oil derivatives	$	195	$	(128	)	$	(861	)	$	(161	)
Natural gas derivatives	22		(5		)	19			(7		)
Total	$	217	$	(133	)	$	(842	)	$	(168	)

The following table represents the Company’s net cash receipts from (payments on) derivatives for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Net cash receipts from (payments on) derivatives:
Oil derivatives	$	(54	)	$	(86	)	$	(51	)	$	(199	)
Natural gas derivatives	4			4			1			5
Total	$	(50	)	$	(82	)	$	(50	)	$	(194	)

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Condensed Notes to Consolidated Financial Statements

June 30, 2019

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Commodity derivative contracts. The following table sets forth the Company’s outstanding derivative contracts at June 30, 2019. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at June 30, 2019 are expected to settle by December 31, 2021.



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
Oil Price Swaps: (a)
2019:
Volume (Bbl)							14,829,000			12,513,000			27,342,000
Price per Bbl							$	57.06		$	56.65		$	56.87
2020:
Volume (Bbl)	11,243,000			10,166,500			9,453,000			9,218,000			40,080,500
Price per Bbl	$	57.48		$	57.24		$	57.18		$	57.14		$	57.27
2021:
Volume (Bbl)	3,330,000			3,367,000			3,220,000			3,220,000			13,137,000
Price per Bbl	$	55.33		$	55.33		$	55.33		$	55.33		$	55.33
Oil Costless Collars: (a)
2019:
Volume (Bbl)							1,135,000			1,058,000			2,193,000
Ceiling price per Bbl							$	63.47		$	62.95		$	63.22
Floor price per Bbl							$	55.74		$	55.43		$	55.60
Oil Basis Swaps: (b)
2019:
Volume (Bbl)							15,778,000			16,053,000			31,831,000
Price per Bbl							$	(2.32	)	$	(2.19	)	$	(2.25	)
2020:
Volume (Bbl)	14,651,000			10,192,000			10,120,000			10,120,000			45,083,000
Price per Bbl	$	(0.46	)	$	(0.70	)	$	(0.71	)	$	(0.71	)	$	(0.63	)
2021:
Volume (Bbl)	3,600,000			3,640,000			3,680,000			3,680,000			14,600,000
Price per Bbl	$	0.57		$	0.57		$	0.57		$	0.57		$	0.57
Natural Gas Price Swaps: (c)
2019:
Volume (MMBtu)							17,298,537			17,209,535			34,508,072
Price per MMBtu							$	2.87		$	2.87		$	2.87
2020:
Volume (MMBtu)	6,233,500			6,233,500			6,118,000			6,118,000			24,703,000
Price per MMBtu	$	2.70		$	2.70		$	2.70		$	2.70		$	2.70

(a) The oil derivative contracts are settled based on the NYMEX – West Texas Intermediate (“WTI”) calendar-month average futures price. (b) The basis differential price is between Midland – WTI and Cushing – WTI. The majority of these contracts are settled on a calendar month basis, while certain contracts assumed in the RSP Acquisition are settled on a trading-month basis. (c) The natural gas derivative contracts are settled based on the NYMEX – Henry Hub last trading day futures price.

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

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

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Note 8. Debt

The Company’s debt consisted of the following at June 30, 2019 and December 31, 2018:



(in millions)	June 30, 2019			December 31, 2018
Credit facility due 2022	$	397		$	242
4.375% unsecured senior notes due 2025 (a)	600			600
3.75% unsecured senior notes due 2027	1,000			1,000
4.3% unsecured senior notes due 2028	1,000			1,000
4.875% unsecured senior notes due 2047	800			800
4.85% unsecured senior notes due 2048	600			600
Unamortized original issue discount	(10		)	(10		)
Senior notes issuance costs, net	(37		)	(38		)
Less: current portion	—			—
Total long-term debt	$	4,350		$	4,194

(a) For each of the twelve-month periods beginning on January 15, 2020, 2021, 2022, 2023 and thereafter, these notes are callable at 103.281%, 102.188%, 101.094% and 100%, respectively.

Credit facility. The Company’s Credit Facility has a maturity date of May 9, 2022. At June 30, 2019, the Company’s commitments from its bank group were $2.0 billion, of which $1.6 billion were unused commitments, net of letters of credit. During the three and six months ended June 30, 2019, the weighted average interest rates on the Credit Facility were 4.3 percent and 4.4 percent, respectively. At June 30, 2019, certain of the Company’s 100 percent owned subsidiaries were guarantors under the Credit Facility.

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 certain of the Company’s 100 percent owned subsidiaries, subject to customary release provisions as described in Note 13, and rank equally in right of payments with one another.

At June 30, 2019, the Company was in compliance with the covenants under all of its debt instruments.

Interest expense. The following amounts have been incurred and charged to interest expense for the three and six months ended June 30, 2019 and 2018:



(in millions)	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Cash payments for interest	$	46		$	42		$	109		$	60
Non-cash interest	2			2			3			3
Net changes in accruals	5			(15		)	(8		)	(3		)
Interest costs incurred	53			29			104			60
Less: capitalized interest	(5		)	(2		)	(9		)	(3		)
Total interest expense	$	48		$	27		$	95		$	57

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Condensed Notes to Consolidated Financial Statements

June 30, 2019

Unaudited

Note 9. Commitments and contingencies

Legal actions. The Company is a party to proceedings and claims incidental to its business. Assessing contingencies is highly subjective and requires judgment about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoing discovery and/or development of information important to the matter. For material matters that the Company believes an unfavorable outcome is reasonably possible, it would disclose the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. The Company does not believe that the loss for any other litigation matters and claims that are reasonably possible to occur will have a material adverse effect on its financial position, results of operations or liquidity. The Company will continue to evaluate proceedings and claims involving the Company on a regular basis and will establish and adjust any estimated accruals as appropriate.

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. Although the Company believes that it has estimated its exposure with respect to the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued.

Commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including water commitment agreements, throughput volume delivery commitments, fixed and variable power commitments, sand commitment agreements, fixed asset commitments and maintenance commitments. The Company’s drilling rig commitments are considered leases under ASU 2016-02 and are included within the tables under the “Leases” section below. The following table summarizes the Company’s commitments at June 30, 2019:



(in millions)
Remaining 2019	$	20
2020	70
2021	77
2022	38
2023	35
2024	36
Thereafter	103
Total	$	379

At June 30, 2019, the Company’s delivery commitments covered the following gross volumes of oil and natural gas:



	Oil (MMBbl)	Natural Gas (MMcf)
Remaining 2019	7	1,582
2020	32	4,792
2021	37	18,931
2022	41	16,425
2023	33	16,425
2024	33	16,470
Thereafter	114	32,850
Total	297	107,475

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Other commitments. In January 2019, the Company entered into a firm sales agreement with a third-party purchaser. The purchaser provides integrated transportation and marketing optionality, including dock capacity in Corpus Christi, Texas. The agreement has a term that ends five years after the completion of certain infrastructure projects and requires the Company to deliver 50,000 barrels of oil per day that will receive waterborne market pricing.

Leases. The Company leases office space, office equipment, drilling rigs, field equipment and vehicles. Right-of-use assets and lease liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. Leased assets may be used in joint operations with other working interest owners. When the Company is the operator in a joint arrangement, the right-of-use assets and lease liabilities are determined on a gross basis. Certain leases contain variable costs above the minimum required payments and are not included in the right-of-use assets or lease liabilities. Options to extend or terminate a lease are included in the lease term when it is reasonably certain the Company will exercise that option. For operating leases, lease cost is recognized on a straight-line basis over the term of the lease. Leases with an initial term of 12 months or less are not recorded on the consolidated balance sheet. The Company elected a practical expedient to not separate non-lease components from lease components for the following asset types: office space, office equipment, drilling rigs, and field equipment. The Company did not elect this practical expedient for vehicle leases.

The following table provides supplemental consolidated balance sheet information related to leases at June 30, 2019:



(in millions)	Classification	June 30, 2019
Assets
Operating lease right-of-use assets	Other property and equipment, net	$	17
Finance lease right-of-use assets	Other property and equipment, net	15
Total lease right-of-use assets (a)		$	32

Liabilities
Current:
Operating	Other current liabilities	$	7
Finance	Other current liabilities	6
Noncurrent:
Operating	Asset retirement obligations and other long-term liabilities	12
Finance	Asset retirement obligations and other long-term liabilities	10
Total lease liabilities (a)		$	35

(a) Total lease right-of-use assets and lease liabilities are gross amounts, and a portion of these costs will be reimbursed by other working interest owners.

As of June 30, 2019, the Company had additional operating leases that have not yet commenced. Future undiscounted lease payments of $15 million and estimated lease incentives of $5 million will be included in the determination of the right-of-use asset and lease liability upon lease commencement.

The following table provides the components of lease cost, excluding lease cost related to short-term leases, for the three and six months ended June 30, 2019:



(in millions)	Classification	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost	General and administrative	$	2	$	4
Finance lease cost	Depreciation, depletion, and amortization (a)	2		4
Total lease cost		$	4	$	8

(a) Interest on lease liabilities related to finance leases was immaterial during the three and six months ended June 30, 2019.

The Company’s short-term leases are comprised primarily of drilling rigs and certain field equipment. During the three and six months ended June 30, 2019, the Company’s gross lease costs related to its short-term leases were $90 million and $184 million,

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June 30, 2019

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respectively, of which $64 million and $131 million, respectively, were capitalized as part of oil and natural gas properties. A portion of these costs was reimbursed to the Company by other working interest owners.

The following table summarizes supplemental cash flow information related to leases for the six months ended June 30, 2019:



(in millions)	Six Months Ended June 30, 2019
Cash paid for amounts included in measurement of lease liabilities:
Operating cash flows from operating leases	$	4
Financing cash flows from finance leases	$	4
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	1
Finance leases	$	4

The following table provides lease terms and discount rates related to leases at June 30, 2019:



	June 30, 2019
Weighted average remaining lease term (years):
Operating leases	3.2
Finance leases	2.8

Weighted average discount rate (a):
Operating leases	4.9	%
Finance leases	4.4	%

(a) The Company uses the rate implicit in the contract, if readily determinable, or its incremental borrowing rate at the commencement date as the discount rate in determining the present value of the lease payments.

The following table provides maturities of lease liabilities at June 30, 2019:



(in millions)	Operating Leases			Finance Leases
Remaining 2019	$	4		$	3
2020	8			6
2021	7			5
2022	1			2
2023	—			1
Thereafter	1			—
Total lease payments	21			17
Less: interest	(2		)	(1		)
Present value of lease liabilities	$	19		$	16

As discussed in Note 2, the Company elected a transition method to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings. Per ASU 2016-02, an entity electing this transition method should provide the required disclosures under Topic 840 for all periods that continue to be in accordance with Topic 840. As such, the Company included the future minimum lease commitments table below as of December 31, 2018. In addition, lease payments associated with these operating leases were $3 million and $6 million for the three and six months ended June 30, 2018, respectively.

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Future minimum lease commitments under non-cancellable leases at December 31, 2018 were as follows:



(in millions)
2019	$	14
2020	12
2021	10
2022	3
2023	—
Thereafter	1
Total	$	40

Note 10. Income taxes

The Company’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items. For the three months ended June 30, 2019 and 2018, the Company recorded an income tax benefit of $53 million and income tax expense of $40 million, respectively, and an income tax benefit of $247 million and income tax expense of $294 million for the six months ended June 30, 2019 and 2018, respectively. The change in the income tax provision as compared to 2018 was primarily due to a pre-tax loss for the three and six months ended June 30, 2019 as compared to pre-tax income for the respective periods in 2018.

The effective income tax rates were 35 percent and 23 percent for the three months ended June 30, 2019 and 2018, respectively, and 24 percent and 23 percent for the six months ended June 30, 2019 and 2018, respectively.

The difference between the Company’s effective tax rates for the three and six months ended June 30, 2019 as compared to the same periods in 2018 was primarily due to a pre-tax loss in 2019 and the research and development credit, net of unrecognized tax benefits, recorded in 2019. The Company recorded a discrete income tax benefit related to stock-based awards of $1 million and $3 million for the six months ended June 30, 2019 and 2018, respectively.

During the second quarter of 2019, the state of New Mexico enacted a tax law which, among other changes, amended the net operating loss apportioned carryforwards for corporations. As a result of this law change, the Company recorded an estimated deferred state tax benefit of $6 million during the three and six months ended June 30, 2019.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based upon the technical merits of the position. At December 31, 2018, the Company had cumulative unrecognized tax benefits of approximately $63 million, primarily related to research and development credits. As of June 30, 2019, the Company estimated an increase in cumulative unrecognized tax benefits for the 2019 tax year of approximately $16 million. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period recognized. The timing as to when the Company will substantially resolve the uncertainties associated with the unrecognized tax benefit is uncertain.

Note 11. Related party transactions

The Company paid royalties on certain properties to a partnership in which a director of the Company is the general partner and owns a 3.5 percent limited partnership interest. These payments totaled $2 million and $3 million for the three months ended June 30, 2019 and 2018, respectively, and $4 million for both the six months ended June 30, 2019 and 2018.

At June 30, 2019, the Company had ownership interests in entities that operate and manage various infrastructure assets and accounts for these investments using the equity method. The payments to these entities totaled $11 million and $15 million for the three and six months ended June 30, 2019, respectively.

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Condensed Notes to Consolidated Financial Statements

June 30, 2019

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Note 12. Earnings per share

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

The Company’s basic earnings (loss) per share attributable to common stockholders is computed as (i) net income (loss) as reported, (ii) less participating basic earnings (iii) divided by weighted average basic common shares outstanding. The Company’s diluted earnings (loss) per share attributable to common stockholders is computed as (i) basic earnings (loss) attributable to common stockholders, (ii) plus reallocation of participating earnings (iii) divided by weighted average diluted common shares outstanding.

The following table reconciles the Company’s earnings (loss) from operations and earnings (loss) attributable to common stockholders to the basic and diluted earnings (loss) used to determine the Company’s earnings (loss) per share amounts for the three and six months ended June 30, 2019 and 2018 under the two-class method:



	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Net income (loss) as reported	$	(97	)	$	137		$	(792	)	$	972
Participating basic earnings (a)	—			(1		)	—			(8		)
Basic earnings (loss) attributable to common stockholders	(97		)	136			(792		)	964
Reallocation of participating earnings	—			—			—			—
Diluted earnings (loss) attributable to common stockholders	$	(97	)	$	136		$	(792	)	$	964

(a) Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity holders of the Company. Participating earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so.

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,		Six Months Ended June 30,
(in thousands)	2019	2018	2019	2018
Weighted average common shares outstanding:
Basic	199,185	147,938	199,184	147,931
Dilutive performance units	—	177	—	357
Diluted	199,185	148,115	199,184	148,288

The following table is a summary of the performance units that were not included in the computation of diluted earnings per share, as inclusion of these items would be antidilutive:



	Three Months Ended June 30,		Six Months Ended June 30,
(in thousands)	2019	2018	2019	2018
Number of antidilutive units:
Performance units	431	218	430	109

Performance unit awards. The number of shares of common stock that will ultimately be issued for performance units will be determined by a combination of (i) comparing the Company’s total stockholder return relative to the total stockholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total stockholder return at the end of the performance period. The performance period on these awards can range from three to five years. The actual payout of shares will be between zero and 300 percent. See Note 5 for additional information on performance unit awards.

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Condensed Notes to Consolidated Financial Statements

June 30, 2019

Unaudited

Note 13. Subsidiary guarantors

At June 30, 2019, certain of the Company’s 100 percent owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be 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 8 for a summary of the Company’s senior notes. In accordance with practices accepted by the SEC, the Company has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. In addition, certain of the Company’s subsidiaries do not guarantee the Company’s senior notes and are included in the Company’s consolidated financial statements. These entities are 100 percent owned subsidiaries and are referred to as a “Subsidiary Non-Guarantor” in the tables below. The Company’s less than 100 percent owned subsidiaries, primarily equity method investments, do not guarantee the Company’s senior notes.

The following condensed consolidating balance sheets at June 30, 2019 and December 31, 2018, condensed consolidating statements of operations for the three and six months ended June 30, 2019 and 2018 and condensed consolidating statements of cash flows for the six months ended June 30, 2019 and 2018, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the subsidiary non-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 and subsidiary non-guarantors are not restricted from making distributions to the Company.

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June 30, 2019

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Condensed Consolidating Balance Sheet
June 30, 2019
(in millions)	Parent Issuer		Subsidiary Guarantors		Subsidiary Non-Guarantor		Consolidating Entries			Total
ASSETS
Accounts receivable - related parties	$	18,181	$	—	$	—	$	(18,181	)	$	—
Other current assets	25		835		—		—			860
Oil and natural gas properties, net	—		21,826		16		—			21,842
Property and equipment, net	—		374		—		—			374
Investment in subsidiaries	5,310		—		—		(5,310		)	—
Goodwill	—		2,222		—		—			2,222
Other long-term assets	43		137		—		—			180
Total assets	$	23,559	$	25,394	$	16	$	(23,491	)	$	25,478

LIABILITIES AND EQUITY
Accounts payable - related parties	$	—	$	18,165	$	16	$	(18,181	)	$	—
Other current liabilities	192		1,211		—		—			1,403
Long-term debt	4,350		—		—		—			4,350
Other long-term liabilities	1,058		708		—		—			1,766
Equity	17,959		5,310		—		(5,310		)	17,959
Total liabilities and equity	$	23,559	$	25,394	$	16	$	(23,491	)	$	25,478



Condensed Consolidating Balance Sheet
December 31, 2018
(in millions)	Parent Issuer		Subsidiary Guarantors		Subsidiary Non-Guarantor		Consolidating Entries			Total
ASSETS
Accounts receivable - related parties	$	18,155	$	—	$	—	$	(18,155	)	$	—
Other current assets	534		875		—		—			1,409
Oil and natural gas properties, net	—		21,988		17		—			22,005
Property and equipment, net	—		308		—		—			308
Investment in subsidiaries	5,411		—		—		(5,411		)	—
Goodwill	—		2,224		—		—			2,224
Other long-term assets	224		124		—		—			348
Total assets	$	24,324	$	25,519	$	17	$	(23,566	)	$	26,294

LIABILITIES AND EQUITY
Accounts payable - related parties	$	—	$	18,138	$	17	$	(18,155	)	$	—
Other current liabilities	70		1,286		—		—			1,356
Long-term debt	4,194		—		—		—			4,194
Other long-term liabilities	1,292		684		—		—			1,976
Equity	18,768		5,411		—		(5,411		)	18,768
Total liabilities and equity	$	24,324	$	25,519	$	17	$	(23,566	)	$	26,294

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June 30, 2019

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Condensed Consolidating Statement of Operations
Three Months Ended June 30, 2019
(in millions)	Parent Issuer			Subsidiary Guarantors			Subsidiary Non-Guarantor		Consolidating Entries		Total
Total operating revenues	$	—		$	1,127		$	—	$	—	$	1,127
Total operating costs and expenses	217			(1,749		)	—		—		(1,532		)
Income (loss) from operations	217			(622		)	—		—		(405		)
Interest expense	(48		)	—			—		—		(48		)
Other, net	(319		)	303			—		319		303
Loss before income taxes	(150		)	(319		)	—		319		(150		)
Income tax benefit	53			—			—		—		53
Net loss	$	(97	)	$	(319	)	$	—	$	319	$	(97	)



Condensed Consolidating Statement of Operations
Three Months Ended June 30, 2018
(in millions)	Parent Issuer			Subsidiary Guarantors			Subsidiary Non-Guarantor		Consolidating Entries			Total
Total operating revenues	$	—		$	945		$	—	$	—		$	945
Total operating costs and expenses	(134		)	(608		)	—		—			(742		)
Income (loss) from operations	(134		)	337			—		—			203
Interest expense	(27		)	—			—		—			(27		)
Other, net	338			1			—		(338		)	1
Income before income taxes	177			338			—		(338		)	177
Income tax expense	(40		)	—			—		—			(40		)
Net income	$	137		$	338		$	—	$	(338	)	$	137

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June 30, 2019

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Condensed Consolidating Statement of Operations
Six Months Ended June 30, 2019
(in millions)	Parent Issuer			Subsidiary Guarantors			Subsidiary Non-Guarantor		Consolidating Entries		Total
Total operating revenues	$	—		$	2,231		$	—	$	—	$	2,231
Total operating costs and expenses	(843		)	(2,639		)	—		—		(3,482		)
Loss from operations	(843		)	(408		)	—		—		(1,251		)
Interest expense	(95		)	—			—		—		(95		)
Other, net	(101		)	307			—		101		307
Loss before income taxes	(1,039		)	(101		)	—		101		(1,039		)
Income tax benefit	247			—			—		—		247
Net loss	$	(792	)	$	(101	)	$	—	$	101	$	(792	)



Condensed Consolidating Statement of Operations
Six Months Ended June 30, 2018
(in millions)	Parent Issuer			Subsidiary Guarantors			Subsidiary Non-Guarantor			Consolidating Entries			Total
Total operating revenues	$	—		$	1,887		$	5		$	—		$	1,892
Total operating costs and expenses	(168		)	(503		)	(3		)	—			(674		)
Income (loss) from operations	(168		)	1,384			2			—			1,218
Interest expense	(57		)	—			—			—			(57		)
Other, net	1,491			105			—			(1,491		)	105
Income before income taxes	1,266			1,489			2			(1,491		)	1,266
Income tax expense	(294		)	—			—			—			(294		)
Net income	$	972		$	1,489		$	2		$	(1,491	)	$	972

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June 30, 2019

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Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2019
(in millions)	Parent Issuer			Subsidiary Guarantors			Subsidiary Non-Guarantor		Consolidating Entries		Total
Net cash flows provided by (used in) operating activities	$	(91	)	$	1,493		$	—	$	—	$	1,402
Net cash flows used in investing activities	—			(1,473		)	—		—		(1,473		)
Net cash flows provided by (used in) financing activities	91			(20		)	—		—		71
Net change in cash and cash equivalents	—			—			—		—		—
Cash and cash equivalents at beginning of period	—			—			—		—		—
Cash and cash equivalents at end of period	$	—		$	—		$	—	$	—	$	—



Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2018
(in millions)	Parent Issuer			Subsidiary Guarantors			Subsidiary Non-Guarantor		Consolidating Entries		Total
Net cash flows provided by operating activities	$	354		$	736		$	—	$	—	$	1,090
Net cash flows used in investing activities	—			(565		)	—		—		(565		)
Net cash flows used in financing activities	(354		)	(116		)	—		—		(470		)
Net increase in cash and cash equivalents	—			55			—		—		55
Cash and cash equivalents at beginning of period	—			—			—		—		—
Cash and cash equivalents at end of period	$	—		$	55		$	—	$	—	$	55

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Note 14. Subsequent events

Joint venture. In July 2019, the Company contributed certain water infrastructure assets primarily in Eddy County, New Mexico to Solaris Midstream Holdings, LLC (“Solaris”). Solaris owns and operates produced water gathering, transportation, disposal, recycling and storage infrastructure assets in the Permian Basin. In exchange, the Company received a cash distribution and a 20 percent equity ownership in Solaris. In conjunction with the transaction, the Company entered into a water gathering and disposal agreement with Solaris.

New commodity derivative contracts. After June 30, 2019, the Company entered into the following derivative contracts to hedge additional amounts of estimated future production:



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
Oil Price Swaps – WTI: (a)
2019:
Volume (Bbl)							1,741,000			—			1,741,000
Price per Bbl							$	56.08		$	—		$	56.08
Oil Price Swaps – Brent: (b)
2019:
Volume (Bbl)							—			1,810,000			1,810,000
Price per Bbl							$	—		$	62.48		$	62.48
2020:
Volume (Bbl)	1,001,000			1,001,000			1,012,000			1,012,000			4,026,000
Price per Bbl	$	61.03		$	61.03		$	61.03		$	61.03		$	61.03
Natural Gas Price Swaps: (c)
2020:
Volume (MMBtu)	9,100,000			9,100,000			9,200,000			9,200,000			36,600,000
Price per MMBtu	$	2.45		$	2.45		$	2.45		$	2.45		$	2.45
2021:
Volume (MMBtu)	7,200,000			7,280,000			7,360,000			7,360,000			29,200,000
Price per MMBtu	$	2.52		$	2.52		$	2.52		$	2.52		$	2.52
Natural Gas Basis Swaps: (d)
2019:
Volume (Bbl)							2,400,000			7,360,000			9,760,000
Price per Bbl							$	(0.70	)	$	(0.70	)	$	(0.70	)
2020:
Volume (MMBtu)	7,280,000			7,280,000			7,360,000			7,360,000			29,280,000
Price per MMBtu	$	(1.04	)	$	(1.04	)	$	(1.04	)	$	(1.04	)	$	(1.04	)

(a) These oil derivative contracts are settled based on the NYMEX – WTI calendar-month average futures price.
(b) These oil derivative contracts are settled based on the Brent calendar-month average futures price.
(c) The natural gas derivative contracts are settled based on the NYMEX – Henry Hub last trading day futures price.
(d) The basis differential price is between NYMEX – Henry Hub and El Paso Permian.

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Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

June 30, 2019

Unaudited

Note 15. Supplementary information

Capitalized costs



(in millions)	June 30, 2019			December 31, 2018
Oil and natural gas properties:
Proved	$	26,824		$	24,992
Unproved	6,497			6,714
Less: accumulated depletion	(11,479		)	(9,701		)
Net capitalized costs for oil and natural gas properties	$	21,842		$	22,005

Costs incurred for oil and natural gas producing activities



	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2019		2018		2019		2018
Property acquisition costs:
Proved	$	—	$	—	$	—	$	—
Unproved	9		5		13		18
Exploration	435		335		897		578
Development	350		166		814		373
Total costs incurred for oil and natural gas properties	$	794	$	506	$	1,724	$	969

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

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

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

Overview

Concho Resources Inc. (“Concho,” the “Company,” “we,” “us,” and “our”) is an independent exploration and production company. We are one of the largest operators in the Permian Basin of West Texas and Southeast New Mexico. Concho’s legacy in the Permian Basin provides us a deep understanding of operating and geological trends, and we are actively developing our resource base by utilizing large-scale development projects, which include long-lateral wells, enhanced completion techniques and multi-well pad locations, throughout our operating areas.

Financial and Operating Performance

On July 19, 2018, we completed our acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”), which, among other things, impacted the comparability of our results of operations. Our financial and operating performance for the six months ended June 30, 2019 and 2018 included the following highlights:


•	Net loss was $792 million ($(3.98) per diluted share) as compared to net income of $972 million ($6.50 per diluted share) for the six months ended June 30, 2019 and 2018, respectively. The decrease in net income was primarily due to:


•	$868 million in non-cash impairments of long-lived assets during the six months ended June 30, 2019;


•	$674 million increase in loss on derivatives due to a $842 million loss on derivatives during the six months ended June 30, 2019, as compared to $168 million during 2018;


•	$724 million decrease in gain on disposition of assets, primarily due to the gains related to certain acquisitions and divestitures during 2018, as discussed in Note 4 of the Condensed Notes to Consolidated Financial Statements;


•	$316 million increase in depreciation, depletion and amortization expense, primarily due to the increase in production and the increase in depletion rate per Boe; and


•	$102 million increase in production expense, primarily due to increased production and activities associated with an increase in well count due to acquisitions in 2018 and additional wells successfully drilled and completed in 2018 and 2019;

partially offset by:


•	$339 million increase in oil and natural gas revenues as a result of a 44 percent increase in production, partially offset by a 18 percent decrease in commodity price realizations per Boe (excluding the effects of derivative activities); and


•	$202 million increase in other income during the six months ended June 30, 2019, primarily due to the gain of $289 million on the sale of our ownership interest in the subsidiary of our equity method investment, Oryx Southern Delaware Holdings, LLC (“Oryx”).


•	Average daily sales volumes of 329 MBoe per day during the six months ended June 30, 2019 increased 44 percent as compared to 228 MBoe per day during the same period in 2018.


•	Net cash provided by operating activities increased by $312 million to $1,402 million for the six months ended June 30, 2019, as compared to $1,090 million in the six months ended June 30, 2018, primarily due to an increase in oil and natural gas revenues and changes related to cash settlements on derivatives, partially offset by increased operating costs on our oil and natural gas properties.

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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 and natural gas, (ii) market uncertainty and (iii) a variety of additional factors that are beyond our control. Factors that may impact future commodity prices, including the price of oil and natural gas, include but are not limited to:


•	the overall global demand for oil and natural gas;


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


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


•	the U.S. economy,


•	weather conditions, and


•	liquefied natural gas (“LNG”) deliveries to and exports from the United States;


•	economic conditions worldwide;


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


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


•	the quality of the oil we produce;


•	the level of global crude oil, crude oil products and LNG inventories;


•	volatility and trading patterns in the commodity-futures markets;


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


•	the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to influence global oil supply levels;


•	technological advances affecting energy consumption and energy supply;


•	the effect of energy conservation efforts;


•	additional restrictions on the exploration, development and production of oil, natural gas and natural gas liquids so as to materially reduce emissions of carbon dioxide and methane greenhouse gases;


•	political and economic events that directly or indirectly impact the relative strength or weakness of the U.S. dollar, on which oil prices are benchmarked globally, against foreign currencies;


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


•	the cost and availability of products and personnel needed for us to produce oil and natural gas, including rigs, crews, sand, water and water disposal; and


•	the price, availability and acceptance of alternative fuels.

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 may hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Notes 7 and 14 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 June 30, 2019 and additional derivative contracts entered into subsequent to June 30, 2019, respectively.

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The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three and six months ended June 30, 2019 and 2018, as well as the high and low NYMEX prices for the same periods:



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Average NYMEX prices:
Oil (Bbl)	$	59.86	$	67.85	$	57.38	$	65.42
Natural gas (MMBtu)	$	2.51	$	2.83	$	2.69	$	2.84

High and Low NYMEX prices:
Oil (Bbl):
High	$	66.30	$	74.15	$	66.30	$	74.15
Low	$	51.14	$	62.06	$	45.41	$	59.19
Natural gas (MMBtu):
High	$	2.71	$	3.02	$	3.59	$	3.63
Low	$	2.19	$	2.66	$	2.19	$	2.55

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $60.43 and $55.30 per Bbl and $2.45 and $2.14 per MMBtu, respectively, during the period from July 1, 2019 to July 30, 2019. At July 30, 2019, the NYMEX oil price and NYMEX natural gas price were $58.05 per Bbl and $2.14 per MMBtu, respectively.

Historically, and during the three and six months ended June 30, 2019, we derived a significant portion of our total natural gas revenues from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. The average Mont Belvieu price for a blended barrel of natural gas liquids was $20.16 per Bbl and $29.72 per Bbl during the three months ended June 30, 2019 and 2018, respectively, and $22.15 per Bbl and $28.68 per Bbl during the six months ended June 30, 2019 and 2018, respectively.

Recent Events

Oryx I divestiture. In May 2019, Oryx, an entity that owned and operated Oryx I, a crude oil gathering and transportation system in the Delaware Basin ("Oryx I"), completed the sale of 100 percent of its equity interests in Oryx I. We received $289 million, net of closing costs, in connection with the sale of Oryx I and used a portion of the proceeds to repay borrowings under our credit facility, as amended and restated (“Credit Facility”).

Midstream joint venture. In April 2019, we entered into a midstream joint venture, Beta Holding Company, LLC (“Beta Holding”), to construct a pipeline to gather and transport oil production in the northern portion of the Midland Basin. We also entered into a ten-year dedication agreement with an affiliate of Beta Holding to transport our oil production in the northern portion of the Midland Basin.

Derivative Financial Instruments

Derivative financial instrument exposure. At June 30, 2019, the fair value of our financial derivatives was a net liability of $97 million. Under the terms of our financial derivative instruments, we do not have exposure to potential “margin calls” on our financial derivative instruments. The terms of our Credit Facility do not allow us to offset amounts we may owe a lender against amounts we may be owed related to our derivative financial instruments with such party.

New commodity derivative contracts. After June 30, 2019, we entered into derivative contracts to hedge additional amounts of estimated future production. Refer to Note 14 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding these commodity derivative contracts.

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Results of Operations

The following table sets forth summary information concerning our production and operating data for the three and six months ended June 30, 2019 and 2018. The actual historical data in this table excludes results from the RSP Acquisition for periods prior to July 19, 2018. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions and divestitures, the historical information presented below should not be interpreted as being indicative of future results.



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Production and operating data:
Net production volumes:
Oil (MBbl)	18,726		13,029		37,662		25,968
Natural gas (MMcf)	67,104		46,837		130,873		92,285
Total (MBoe)	29,910		20,835		59,474		41,349

Average daily production volumes:
Oil (Bbl)	205,780		143,176		208,077		143,470
Natural gas (Mcf)	737,407		514,692		723,055		509,862
Total (Boe)	328,681		228,958		328,586		228,447

Average prices per unit: (a)
Oil, without derivatives (Bbl)	$	56.02	$	60.98	$	52.68	$	61.13
Oil, with derivatives (Bbl) (b)	$	53.15	$	54.34	$	51.35	$	53.47
Natural gas, without derivatives (Mcf)	$	1.16	$	3.19	$	1.88	$	3.29
Natural gas, with derivatives (Mcf) (b)	$	1.22	$	3.29	$	1.89	$	3.34
Total, without derivatives (Boe)	$	37.68	$	45.31	$	37.51	$	45.74
Total, with derivatives (Boe) (b)	$	36.02	$	41.37	$	36.68	$	41.04

Operating costs and expenses per Boe: (a)
Oil and natural gas production	$	6.31	$	6.24	$	6.09	$	6.28
Production and ad valorem taxes	$	2.81	$	3.37	$	2.86	$	3.39
Gathering, processing and transportation	$	0.73	$	0.45	$	0.80	$	0.49
Depreciation, depletion and amortization	$	15.96	$	14.88	$	15.86	$	15.16
General and administrative	$	2.89	$	3.37	$	2.98	$	3.35



(a)	Per unit and per Boe amounts calculated using dollars and volumes rounded to thousands.

(b)	Includes the effect of net cash receipts from (payments on) derivatives:

		Three Months Ended June 30,						Six Months Ended June 30,
	(in millions)	2019			2018			2019			2018
	Net cash receipts from (payments on) derivatives:
	Oil derivatives	$	(54	)	$	(86	)	$	(51	)	$	(199	)
	Natural gas derivatives	4			4			1			5
	Total	$	(50	)	$	(82	)	$	(50	)	$	(194	)


	The presentation of average prices with derivatives is a result of including the net cash receipts from (payments on) commodity derivatives that are presented in our consolidated 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.

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Oil and natural gas revenues. Revenue from oil and natural gas operations was $1,127 million for the three months ended June 30, 2019, an increase of $182 million (19 percent) from $945 million for 2018. Revenue from oil and natural gas operations was $2,231 million for the six months ended June 30, 2019, an increase of $339 million (18 percent) from $1,892 million for 2018. The increase in oil and natural gas revenues during both the three and six months ended June 30, 2019 as compared to the same periods in the prior year was primarily due to the increase in oil and natural gas production, in part due to the RSP Acquisition, partially offset by the decrease in realized oil and natural gas prices (excluding the effects of derivative activities).

Specific factors affecting oil and natural gas revenues include the following:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Net production volumes:
Oil (MBbl)	18,726			13,029			37,662			25,968
Natural gas (MMcf)	67,104			46,837			130,873			92,285

Average prices per unit: (a)
Realized oil price (Bbl)	$	56.02		$	60.98		$	52.68		$	61.13
Differential to NYMEX	$	(3.84	)	$	(6.87	)	$	(4.70	)	$	(4.29	)

Realized natural gas price (Mcf)	$	1.16		$	3.19		$	1.88		$	3.29
Average realized natural gas price as a percentage of NYMEX	46		%	113		%	70		%	116		%


•	total oil production increased 5,697 MBbl (44 percent) and 11,694 MBbl (45 percent) for the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018;

•

average realized oil price (excluding the effects of derivative activities) decreased 8 percent and 14 percent for the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018. The decrease in average realized oil price was primarily due to a decrease in the average NYMEX price. The basis differential (referred to as the “Mid-Cush differential”) between the location of Midland, Texas and Cushing, Oklahoma (settlement location for NYMEX pricing) for our oil directly impacts our realized oil price. For the three months ended June 30, 2019 and 2018, the average market Mid-Cush differentials were price reductions of $2.14 per Bbl and $5.15 per Bbl, respectively. For the six months ended June 30, 2019 and 2018, the average market Mid-Cush differentials were reductions of $3.00 per Bbl and $2.39 per Bbl, respectively;


•	total natural gas production increased 20,267 MMcf (43 percent) and 38,588 MMcf (42 percent) for the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018; and

•

average realized natural gas price (excluding the effects of derivative activities) decreased 64 percent and 43 percent for the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018. We derive a significant portion of our total natural gas revenues from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues, our realized natural gas price (excluding the effects of derivatives) historically reflected a price greater than the related NYMEX natural gas price. However, during the latter part of 2018 and into 2019, amid concerns of rising natural gas production relative to the ability to transport natural gas out of the Permian Basin, the price differential for natural gas residue increased significantly. These widening natural gas residue differentials negatively impacted our realized natural gas prices during the three and six months ended June 30, 2019, but were partially offset by the value of the natural gas liquids. The combination of these factors resulted in a realized natural gas price of 46 percent and 70 percent of the average NYMEX natural gas price for the three and six months ended June 30, 2019, respectively, which falls below our historical amounts. In addition, the average Mont Belvieu price for a blended barrel of natural gas liquids decreased from $29.72 per Bbl and $28.68 per Bbl during the three and six months ended June 30, 2018, respectively, to $20.16 per Bbl and $22.15 per Bbl during the three and six months ended June 30, 2019, respectively.

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Oil and natural gas production expenses. The following table provides the components of our oil and natural gas production expenses for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,
	2019				2018
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Lease operating expenses	$	177	$	5.93	$	121	$	5.81
Workover costs	11		0.38		9		0.43
Total oil and natural gas production expenses	$	188	$	6.31	$	130	$	6.24



	Six Months Ended June 30,
	2019				2018
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Lease operating expenses	$	343	$	5.76	$	242	$	5.84
Workover costs	19		0.33		18		0.44
Total oil and natural gas production expenses	$	362	$	6.09	$	260	$	6.28

Lease operating expenses were $177 million ($5.93 per Boe) for the three months ended June 30, 2019, which was an increase of $56 million from $121 million ($5.81 per Boe) during the same period in 2018. Lease operating expenses were $343 million ($5.76 per Boe) for the six months ended June 30, 2019, which was an increase of $101 million from $242 million ($5.84 per Boe) during the same period in 2018. The increase in lease operating expenses during both the three and six months ended June 30, 2019 as compared to the same periods in the prior year was primarily the result of an increase in well count due to our acquisitions during 2018, primarily the RSP Acquisition, and additional wells successfully drilled and completed during 2018 and 2019.

Workover costs were $11 million ($0.38 per Boe) for the three months ended June 30, 2019, which was an increase of $2 million from $9 million ($0.43 per Boe) during the same period in 2018. Workover costs were $19 million ($0.33 per Boe) for the six months ended June 30, 2019, which was an increase of $1 million from $18 million ($0.44 per Boe) during the same period in 2018. The decrease in workover costs per Boe during both the three and six months ended June 30, 2019 was primarily due to increased production.

Production and ad valorem taxes. The following table provides the components of our production and ad valorem tax expenses for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,
	2019				2018
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Production taxes	$	70	$	2.32	$	64	$	3.07
Ad valorem taxes	14		0.49		6		0.30
Total production and ad valorem taxes	$	84	$	2.81	$	70	$	3.37



	Six Months Ended June 30,
	2019				2018
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Production taxes	$	140	$	2.35	$	128	$	3.10
Ad valorem taxes	30		0.51		12		0.29
Total production and ad valorem taxes	$	170	$	2.86	$	140	$	3.39

Production taxes per unit of production were $2.32 per Boe during the three months ended June 30, 2019, a decrease of 24 percent from $3.07 per Boe during the same period in 2018. Production taxes per unit of production were $2.35 per Boe during the six months ended June 30, 2019, a decrease of 24 percent from $3.10 per Boe during the same period in 2018. For the three and six months ended June 30, 2019, our revenue per Boe (excluding the effects of derivatives) decreased 17 percent and 18 percent, respectively, as compared to the same periods in 2018. The decrease in production taxes per unit of production was due to lower realized revenue per Boe along with a higher percentage of our total production originating in Texas, which has a lower tax rate than New Mexico. Production taxes fluctuate with the market value of our production sold, while ad valorem taxes are generally based on the valuation of our oil and natural gas properties at the beginning of the year, which vary across the different areas in which we operate.

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Ad valorem taxes increased $8 million and $18 million for the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018, primarily due to additional wells drilled and completed, new wells acquired in the RSP Acquisition and an increase in property values and tax rates in certain counties. The increase in ad valorem taxes per Boe was primarily due to an increase in property values and tax rates.

Gathering, processing and transportation costs. The following table shows the gathering, processing and transportation costs for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,
	2019				2018
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Gathering, processing and transportation costs	$	22	$	0.73	$	9	$	0.45



	Six Months Ended June 30,
	2019				2018
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Gathering, processing and transportation costs	$	48	$	0.80	$	20	$	0.49

Gathering, processing and transportation costs were $22 million ($0.73 per Boe) for the three months ended June 30, 2019, an increase of 144 percent from $9 million ($0.45 per Boe) during same period in 2018. Gathering, processing and transportation costs were $48 million ($0.80 per Boe) for the six months ended June 30, 2019, an increase of 140 percent from $20 million ($0.49 per Boe) during same period in 2018. The increase in gathering, processing and transportation costs was primarily due to a certain crude oil gathering and transportation contract that, among other things, was modified to allow repurchase rights. As such, costs related to this contract that were previously recorded as a deduction to revenue during the three and six months ended June 30, 2018, are now recorded in gathering, processing and transportation costs. In addition, contributing to the increase in gathering, processing and transportation costs was the RSP Acquisition and the increase in production. The increase in gathering, processing and transportation costs per Boe was primarily related to the aforementioned crude oil gathering and transportation contract, fixed costs associated with certain contracts and higher priced trucking services in certain areas.

Exploration and abandonments expense. The following table provides the components of our exploration and abandonments expense for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2019		2018		2019		2018
Geological and geophysical	$	3	$	2	$	9	$	7
Leasehold abandonments	12		4		42		14
Other	2		2		13		5
Total exploration and abandonments	$	17	$	8	$	64	$	26

Our geological and geophysical expense for the periods presented above primarily consists of the costs of acquiring and processing subsurface data to better characterize and develop our resources.

We recorded $12 million and $4 million of leasehold abandonments for the three months ended June 30, 2019 and 2018, respectively, and $42 million and $14 million for the six months ended June 30, 2019 and 2018, respectively, primarily related to certain expiring acreage and acreage where we had no future plans to drill located primarily in the Delaware Basin.

Our other expense for the periods presented above primarily consists of surface and title costs on locations that we no longer intend to drill, certain plugging costs, delay rentals and other exploratory well costs. The increase in other expense for the six months ended June 30, 2019, as compared to the same period in 2018 was primarily due to the abandonment of one exploratory well during the first quarter of 2019 as a result of certain mechanical issues encountered during the completion of the well that made it unable to produce hydrocarbons.

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Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,
	2019				2018
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Depletion of proved oil and natural gas properties	$	470	$	15.69	$	303	$	14.59
Depreciation of other property and equipment	7		0.25		6		0.25
Amortization of intangible assets	1		0.02		1		0.04
Total depletion, depreciation and amortization	$	478	$	15.96	$	310	$	14.88



	Six Months Ended June 30,
	2019				2018
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Depletion of proved oil and natural gas properties	$	927	$	15.58	$	614	$	14.86
Depreciation of other property and equipment	14		0.25		11		0.26
Amortization of intangible assets	2		0.03		2		0.04
Total depletion, depreciation and amortization	$	943	$	15.86	$	627	$	15.16



	June 30, 2019		June 30, 2018
Oil price used to estimate proved oil reserves at period end	$	57.90	$	54.15
Natural gas price used to estimate proved natural gas reserves at period end	$	3.02	$	2.92

Depletion of proved oil and natural gas properties was $470 million ($15.69 per Boe) for the three months ended June 30, 2019, an increase of $167 million (55 percent) from $303 million ($14.59 per Boe) for 2018. Depletion of proved oil and natural gas properties was $927 million ($15.58 per Boe) for the six months ended June 30, 2019, an increase of $313 million (51 percent) from $614 million ($14.86 per Boe) for 2018. The increase in depletion expense was primarily due to an increase in production and the depletion rate per Boe. The increase in depletion expense per Boe was primarily due to the RSP Acquisition.

Impairments of long-lived assets. During the three and six months ended June 30, 2019, we recognized a non-cash impairment charge of $868 million that was primarily attributable to certain downward adjustments to our economically recoverable proved oil and natural gas reserves associated with properties in our Yeso field. See Note 6 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on impairments of long-lived assets and the fair value assumptions used. We did not recognize an impairment charge during 2018.

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

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General and administrative expenses. The following table provides components of our general and administrative expenses for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,
	2019						2018
(in millions, except per unit amounts)	Amount			Per Boe			Amount			Per Boe
General and administrative expenses	$	69		$	2.25		$	59		$	2.71
Less: Operating fee reimbursements	(4		)	(0.14		)	(5		)	(0.21		)
Non-cash stock-based compensation	23			0.78			18			0.87
Total general and administrative expenses	$	88		$	2.89		$	72		$	3.37



	Six Months Ended June 30,
	2019						2018
(in millions, except per unit amounts)	Amount			Per Boe			Amount			Per Boe
General and administrative expenses	$	140		$	2.33		$	111		$	2.70
Less: Operating fee reimbursements	(8		)	(0.14		)	(9		)	(0.21		)
Non-cash stock-based compensation	47			0.79			35			0.86
Total general and administrative expenses	$	179		$	2.98		$	137		$	3.35

Total general and administrative expenses were $88 million ($2.89 per Boe) for the three months ended June 30, 2019, an increase of $16 million (22 percent) from $72 million ($3.37 per Boe) during the same period in 2018. Total general and administrative expenses were $179 million ($2.98 per Boe) for the six months ended June 30, 2019, an increase of $42 million (31 percent) from $137 million ($3.35 per Boe) during the same period in 2018. The increases in cash general and administrative and non-cash stock-based compensation expenses were primarily the result of increased employee headcount. The decrease in total general and administrative expenses per Boe was primarily the result of increased production, partially offset by the increase in total general and administrative expenses noted above.

We receive fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and record such reimbursements as reductions to general and administrative expenses on the consolidated statements of operations. We earned reimbursements of $4 million and $5 million during the three months ended June 30, 2019 and 2018, respectively, and $8 million and $9 million during the six months ended June 30, 2019 and 2018, respectively.

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Gain (loss) on derivatives. The following table sets forth the gain (loss) on derivatives for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,					Six Months Ended June 30,
(in millions)	2019		2018			2019			2018
Gain (loss) on derivatives:
Oil derivatives	$	195	$	(128	)	$	(861	)	$	(161	)
Natural gas derivatives	22		(5		)	19			(7		)
Total	$	217	$	(133	)	$	(842	)	$	(168	)

The following table represents our net cash receipts from (payments on) derivatives for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Net cash receipts from (payments on) derivatives:
Oil derivatives	$	(54	)	$	(86	)	$	(51	)	$	(199	)
Natural gas derivatives	4			4			1			5
Total	$	(50	)	$	(82	)	$	(50	)	$	(194	)

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 the future commodity price outlook increases between measurement periods, we will have mark-to-market losses. See Note 6 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding significant judgments made in classifying financial instruments in the fair value hierarchy.

Gain (loss) on disposition of assets, net. During the six months ended June 30, 2018, we recorded a gain on disposition of assets of $724 million due to (i) a non-cash gain of $575 million related to our February 2018 acquisition and divestiture, (ii) a gain of $134 million related to our January 2018 Delaware Basin divestitures and (iii) a gain of $15 million related to certain nonmonetary transactions. See Note 4 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information.

Interest expense. The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Interest expense, as reported	$	48		$	27		$	95		$	57
Capitalized interest	5			2			9			3
Interest expense, excluding impact of capitalized interest	$	53		$	29		$	104		$	60

Weighted average interest rate - credit facility	4.3		%	5.3		%	4.4		%	4.5		%
Weighted average interest rate - senior notes	4.4		%	4.3		%	4.4		%	4.3		%
Total weighted average interest rate	4.4		%	4.3		%	4.4		%	4.3		%

Weighted average credit facility balance	$	630		$	50		$	567		$	130
Weighted average senior notes balance	4,000			2,400			4,000			2,400
Total weighted average debt balance	$	4,630		$	2,450		$	4,567		$	2,530

The increase in interest expense during the three and six months ended June 30, 2019 as compared to the same periods in the prior year was primarily due to the increase in the weighted average debt balance, partially offset by the increase in capitalized interest. The increase in the weighted average debt balance was primarily due to the senior notes issued in connection with the RSP Acquisition and a higher average outstanding balance under the Credit Facility.

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Other, net. During the three and six months ended June 30, 2019, we recorded other income of $303 million and $307 million, respectively, primarily related to $289 million of cash proceeds from the sale of our ownership interest in Oryx I. During the six months ended June 30, 2018, we recorded other income of $105 million primarily related to a cash distribution received from Oryx. See Note 2 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information.

Income tax provisions. We recorded an income tax benefit of $53 million and income tax expense of $40 million for the three months ended June 30, 2019 and 2018, respectively, and an income tax benefit of $247 million and income tax expense of $294 million for the six months ended June 30, 2019 and 2018, respectively. The change in our income tax provision for the three and six months ended June 30, 2019 as compared to the same periods in 2018 was primarily due to a pre-tax loss in 2019 as compared to pre-tax income in 2018.

Our effective income tax rates were 35 percent and 23 percent for the three months ended June 30, 2019 and 2018, respectively, and 24 percent and 23 percent for the six months ended June 30, 2019 and 2018, respectively. The change in our effective income tax rate was primarily due to the pre-tax loss in 2019 and research and development credit, net of unrecognized tax benefits, recorded in 2019. We recorded a discrete income tax benefit related to stock-based awards of $1 million and $3 million for the six months ended June 30, 2019 and 2018, respectively.

During the second quarter of 2019, the state of New Mexico enacted a tax law which, among other changes, amended the net operating loss apportioned carryforwards for corporations. As a result of this law change, we recorded an estimated deferred state tax benefit of $6 million during the three and six months ended June 30, 2019.

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Capital Commitments, Capital Resources and Liquidity

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

2019 capital budget and costs incurred. We expect our 2019 capital spending on drilling and completion activity to range between $2.8 billion and $3.0 billion. Our costs incurred on oil and natural gas properties, excluding acquisitions, during the six months ended June 30, 2019 and 2018 totaled $1.7 billion and $951 million, respectively. Our intent is to manage our capital spending to be within our operating cash flow, excluding unbudgeted acquisitions. The primary reason for the differences in costs incurred and cash flow expenditures was the timing of payments. Our capital expenditures for the six months ended June 30, 2019 were primarily funded from cash flows from operations and borrowings under our Credit Facility.

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.

2019 dividends. On July 30, 2019, the Company’s board of directors approved a cash dividend of $0.125 per share for the third quarter of 2019 that is expected to be paid on September 30, 2019 to stockholders of record as of August 9, 2019. Total cash dividends, including the cash dividends on unvested restricted stock awards, paid to our stockholders during the six months ended June 30, 2019 were $50 million. We intend to continue to pay a quarterly dividend of $0.125 in the near future; however, any payment of future dividends will be at the discretion of our board of directors and may be suspended at any time.

Acquisitions. The following table reflects our expenditures for acquisitions of proved and unproved properties for the six months ended June 30, 2019 and 2018:



	Six Months Ended June 30,
(in millions)	2019		2018
Property acquisition costs:
Proved	$	—	$	—
Unproved	13		18
Total property acquisition costs (a)	$	13	$	18

(a) Total property acquisition costs are comprised primarily of budgeted unproved leasehold acreage acquisitions.

Contractual obligations. Our contractual obligations include long-term debt, cash interest expense on debt, derivative liabilities, asset retirement obligations, employment agreements with officers, purchase obligations, operating and finance lease obligations and other obligations. Since December 31, 2018, there have been the following material changes in our contractual obligations:


•	$155 million increase in long-term debt due to additional borrowings under our Credit Facility;


•	$138 million increase in our derivative liability position; and


•	a marketing contract as described below.

Marketing contract. Consistent with our strategy of diversifying our oil pricing, in January 2019, we entered into a firm sales agreement with a third-party purchaser. The purchaser provides integrated transportation and marketing optionality, including dock capacity in Corpus Christi, Texas. The agreement has a term that ends five years after the completion of certain infrastructure projects and requires us to deliver 50,000 barrels of oil per day that will receive waterborne market pricing.

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

Capital resources. Our primary sources of liquidity have been cash flows generated from (i) operating activities, (ii) borrowings under our Credit Facility, (iii) asset dispositions and (iv) proceeds from bond and equity offerings. In October 2018, our board of directors approved our 2019 capital budget of up to $3.8 billion. With current commodity prices, we expect to spend between $2.8 billion and $3.0 billion on drilling and completion activity. We expect to fund our 2019 capital budget with operating cash flows and borrowings under our Credit Facility.

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The following table summarizes our changes in cash and cash equivalents for the six months ended June 30, 2019 and 2018:



	Six Months Ended June 30,
(in millions)	2019			2018
Net cash provided by operating activities	$	1,402		$	1,090
Net cash used in investing activities	(1,473		)	(565		)
Net cash provided by (used in) financing activities	71			(470		)
Net increase in cash and cash equivalents	$	—		$	55

Cash flow from operating activities. The increase in operating cash flows during the six months ended June 30, 2019 as compared to the same period in 2018 was primarily due to an increase in oil and natural gas revenues of $339 million and an increase of $144 million due to $50 million of settlements paid on derivatives during the six months ended June 30, 2019, as compared to $194 million during the comparable period in 2018. The increase was partially offset by increased operating costs on our oil and natural gas properties and increased cash general and administrative expenses.

Our net cash provided by operating activities included a benefit of $33 million and a reduction of $11 million for the six months ended June 30, 2019 and 2018, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

Cash flow from investing activities. Our investing activities consist primarily of drilling and completion activity, acquisitions and divestitures. The primary difference between costs incurred on oil and natural gas properties, including acquisitions, and cash flow expenditures is the timing of payments and the issuances of shares of common stock to fund certain acquisitions.

For the six months ended June 30, 2019, our net cash used in investing activities was $1.5 billion, which consisted primarily of our investment of $1.7 billion for additions to oil and natural gas properties. This was partially offset by $311 million of cash proceeds from asset dispositions primarily due to $289 million in connection with the sale of Oryx I. We used the proceeds of this sale to repay a portion of our outstanding balance under our Credit Facility. Our capital expenditures for the six months ended June 30, 2019 were funded with cash flows from operations and borrowings under our Credit Facility.

For the six months ended June 30, 2018, our net cash used in investing activities was $565 million, which consisted primarily of our investment of $941 million for additions to oil and natural gas properties, partially offset by $261 million of proceeds received from asset dispositions and a distribution received from our equity method investment. We received a distribution from Oryx of $157 million during the six months ended June 30, 2018. Of this amount, $9 million represented cumulative Oryx earnings and was classified as cash flow from operating activities, while the remaining amount of $148 million was classified as cash flow from investing activities.

Cash flow from financing activities. For the six months ended June 30, 2019, our net cash provided by financing activities was $71 million primarily due to $155 million of net borrowings under our Credit Facility partially offset by $50 million of dividends paid on our common stock. During the six months ended June 30, 2019 we decreased our book overdraft by $16 million. For the six months ended June 30, 2018, our net cash used in financing activities was $470 million, primarily due to $322 million of net payments on our Credit Facility. In addition, during the six months ended June 30, 2018, we decreased our book overdrafts by approximately $116 million.

Advances on our Credit Facility bear interest, at our option, based on:


(i)	an alternative base rate (“ABR”), which is equal to the highest of


(a)	the prime rate of JPMorgan Chase Bank (5.5 percent at June 30, 2019),


(b)	the federal funds effective rate plus 0.5 percent, and


(c)	the London Interbank Offered Rate (“LIBOR”) plus 1.0 percent; or


(ii)	LIBOR plus 1.5 percent.

Our Credit Facility’s interest rates and commitment fees on the unused portion of the available commitment vary depending on our credit ratings from Moody’s Investors Service, Inc. (“Moody’s”) and S&P Global Ratings (“S&P”). At our current credit ratings, LIBOR Rate Loans and Alternate Base Rate Loans bear interest margins of 150 basis points and 50 basis points per annum, respectively, and commitment fees on the unused portion of the available commitment are 25 basis points per annum.

In conducting our business, we may utilize various financing sources, including the issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock, (iv) common stock and (v) other securities. Historically, we have demonstrated our use of the capital markets by issuing common stock and senior unsecured debt. There are no assurances that we can access the

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capital markets to obtain additional funding, if needed, and at cost and terms that are favorable to us. We may also sell assets and issue securities in exchange for oil and natural gas assets or interests in energy companies. Additional securities may be of a class senior to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined from time to time. Utilization of some of these financing sources may require approval from the lenders under our Credit Facility.

Liquidity. Our principal source of liquidity is the available borrowing capacity under our Credit Facility. At June 30, 2019, our commitments from our bank group were $2.0 billion, of which $1.6 billion were unused commitments.

Debt ratings. We receive debt credit ratings from S&P, Moody’s and Fitch Ratings and are designated as investment grade with all three agencies. In determining our ratings, the agencies perform regular reviews and consider a number of qualitative and quantitative factors including, but not limited to: the industry in which we operate, production growth opportunities, liquidity, debt levels and asset and reserve mix.

A downgrade in our credit ratings could (i) negatively impact our cost of capital and our ability to effectively execute aspects of our strategy, (ii) affect our ability to raise debt in the public debt markets, and the cost of any new debt could be much higher than our outstanding debt and (iii) negatively affect our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. Further, if we are unable to maintain credit ratings of “Ba2” or better from Moody’s and “BB” or better from S&P, the investment grade period under our Credit Facility will automatically terminate and cause our Credit Facility to once again be secured by a first lien on substantially all of our oil and natural gas properties and by a pledge of the equity interests in our subsidiaries. These and other impacts of a downgrade in our credit ratings could have an adverse effect on our business, financial condition and results of operations.

As of the filing of this Quarterly Report on Form 10-Q, no changes in our credit ratings have occurred; however, we cannot be certain that our credit ratings will not be downgraded in the future.

Book capitalization and current ratio. Our net book capitalization at June 30, 2019 was $22.4 billion, consisting of debt of $4.4 billion and stockholders’ equity of $18.0 billion. Our net book capitalization at December 31, 2018 was $23.0 billion, consisting of debt of $4.2 billion and stockholders’ equity of $18.8 billion. Our ratio of net debt to net book capitalization was 19 percent and 18 percent at June 30, 2019 and December 31, 2018, respectively. Our ratio of current assets to current liabilities was 0.61 to 1.0 at June 30, 2019 as compared to 1.04 to 1.0 at December 31, 2018.

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Critical Accounting Policies, Practices and Estimates

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

In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are 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, accounting and valuation of nonmonetary transactions, goodwill impairment, litigation and environmental contingencies, valuation of financial derivative instruments, uncertain tax positions and income taxes.

There have been no material changes in our critical accounting policies and procedures during the six months ended June 30, 2019. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the Securities and Exchange Commission (“SEC”) on February 20, 2019.

New accounting pronouncements issued but not yet adopted. See Note 2 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for information regarding new accounting pronouncements issued but not yet adopted.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2018.

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 June 30, 2019, 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.

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

Commodity price risk. We are exposed to market risk as the prices of our commodities are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of our commodities, we have entered into, and may in the future enter into, additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Our commodity price risk management arrangements are recorded at fair value and thus changes to the future commodity prices will have an impact on our earnings. The following table sets forth the hypothetical impact on the fair value of the commodity price risk management arrangements from an average increase and decrease in the commodity price of $5.00 per Bbl of oil and $0.50 per MMBtu of natural gas from the commodity prices at June 30, 2019:



(in millions)	Increase of $5.00 per Bbl and $0.50 per MMBtu			Decrease of $5.00 per Bbl and $0.50 per MMBtu
Gain (loss):
Oil derivatives	$	(403	)	$	403
Natural gas derivatives	(26		)	26
Total	$	(429	)	$	429

At June 30, 2019, we had (i) oil price swaps and oil costless collars covering future oil production from July 1, 2019 through December 31, 2021 and (ii) oil basis swaps covering our Midland to Cushing basis differential from July 1, 2019 to December 31, 2021. The NYMEX oil price at June 30, 2019 was $58.47 per Bbl. At July 30, 2019, the NYMEX oil price was $58.05 per Bbl.

At June 30, 2019, we had natural gas price swaps that settle on a monthly basis covering future natural gas production from July 1, 2019 to December 31, 2020. The NYMEX natural gas price at June 30, 2019 was $2.31 per MMBtu. At July 30, 2019, the NYMEX natural gas price was $2.14 per MMBtu.

A decrease in the average forward NYMEX oil and natural gas prices below those at June 30, 2019 would decrease the fair value liability of our commodity derivative contracts from their recorded balance at June 30, 2019. Changes in the recorded fair value of our 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 June 30, 2019 would increase the fair value liability of our commodity derivative contracts from their recorded balance at June 30, 2019. 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.

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We recorded a loss on derivatives of $842 million and $168 million for the six months ended June 30, 2019 and 2018, respectively. The increase in loss on derivatives was primarily due to the change in commodity future price curves at the respective measurement and settlement periods.

The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method for our derivative instruments during the six months ended June 30, 2019. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the six months ended June 30, 2019:



(in millions)	Commodity Derivative Instruments Net Assets (Liabilities)
Fair value of contracts outstanding at December 31, 2018	$	695
Changes in fair values (a)	(842		)
Contract maturities	50
Fair value of contracts outstanding at June 30, 2019 (b)	$	(97	)

(a) At inception, new derivative contracts entered into by us have no intrinsic value.
(b) Represents the fair value of open derivative contracts subject to market risk.

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

Interest rate risk. Our exposure to changes in interest rates relates primarily to debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. To reduce our exposure to changes in interest rates we may, in the future, enter into interest rate risk management arrangements for a portion of our outstanding debt. The agreements that we have entered into generally have the effect of providing us with a fixed interest rate for a portion of our variable rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We are exposed to changes in interest rates as a result of our Credit Facility, and the terms of our Credit Facility require us to pay higher interest rate margins as our credit ratings decrease.

We had total indebtedness of $397 million outstanding under our Credit Facility at June 30, 2019. The impact of a one percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $4 million.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at June 30, 2019 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting. There have been no changes in our internal control 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 control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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, 2018.

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

The following table sets forth our share repurchase activity for each period presented:



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
April 1, 2019 - April 30, 2019	458	$	115.42	—	—
May 1, 2019 - May 31, 2019	133	$	112.49	—	—
June 1, 2019 - June 30, 2019	9,922	$	105.76	—	—

(a) Represents shares that were withheld by us to satisfy tax withholding obligations of certain employees that arose upon the lapse of restrictions on share-based awards.

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Item 6. Exhibits



Exhibit No.		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		Fourth Amended and Restated Bylaws of Concho Resources Inc., as amended January 2, 2018 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on January 4, 2018, and incorporated herein by reference).

10.1	**	Concho Resources Inc. 2019 Stock Incentive Plan, effective March 25, 2019 (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on May 17, 2019, and incorporated herein by reference).

10.2	(a)	Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 29, 2019, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent.

31.1	(a)	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2	(a)	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32.1	(b)	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

32.2	(b)	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

101.INS	(a)	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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.

104	(a)	The cover page of Concho Resources Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2019, formatted in iXBRL (Inline eXtensible Business Reporting Language) and included within the Exhibit 101 attachments.

(a) Filed herewith. (b) Furnished herewith. ** Management contract or compensatory plan or arrangement.

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SIGNATURES

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



CONCHO RESOURCES INC.

Date:	August 1, 2019	By	/s/ Timothy A. Leach

			Timothy A. Leach
			Chairman of the Board of Directors and Chief
			Executive Officer
			(Principal Executive Officer)


		By	/s/ Brenda R. Schroer

			Brenda R. Schroer
			Senior Vice President, Chief Financial Officer and
			Treasurer
			(Principal Financial Officer)


		By	/s/ Jacob P. Gobar

			Jacob P. Gobar
			Vice President and Chief Accounting Officer
			(Principal Accounting Officer)