10-Q

 

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 March 31, 2019

or

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

For the transition period from to

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)

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

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

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

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  ☑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 ☑	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 ☑

Number of shares of the registrant’s common stock outstanding at April 29, 2019: 200,594,025 shares

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION:		iii
	Item 1. Consolidated Financial Statements (Unaudited)	iii
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
	Item 3. Quantitative and Qualitative Disclosures About Market Risk	49
	Item 4. Controls and Procedures	51
PART II – OTHER INFORMATION:		52
	Item 1. Legal Proceedings	52
	Item 1A. Risk Factors	52
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	53
	Item 6. Exhibits	54

i

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 II, Item 1A. Risk Factors” in this Quarterly Report and 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;

·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;

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

·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;

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

·competition in the oil and natural gas industry;

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

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

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

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

·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;

·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;

·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;

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

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

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

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

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and 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.

ii

PART I – FINANCIAL INFORMATION

Item 1.  Consolidated Financial Statements (Unaudited)

Consolidated Balance Sheets at March 31, 2019 and December 31, 2018	1
Consolidated Statements of Operations for the Three Months Ended March 31, 2019 and 2018	2
Consolidated Statements of Stockholders’ Equity for the Three Months Ended March 31, 2019 and 2018	3
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2019 and 2018	4
Condensed Notes to Consolidated Financial Statements	5

iii

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited

				March 31,		December 31,
(in millions, except share and per share amounts)				2019		2018
Assets
Current assets:
	Cash and cash equivalents			$	-	$	-
	Accounts receivable, net of allowance for doubtful accounts:
		Oil and natural gas			530		466
		Joint operations and other			413		365
	Inventory				34		35
	Derivative instruments				1		484
	Prepaid costs and other				49		59
			Total current assets		1,027		1,409
Property and equipment:
	Oil and natural gas properties, successful efforts method				32,559		31,706
	Accumulated depletion and depreciation				(10,138)		(9,701)
		Total oil and natural gas properties, net			22,421		22,005
	Other property and equipment, net				350		308
		Total property and equipment, net			22,771		22,313
Deferred loan costs, net					9		10
Goodwill					2,229		2,224
Intangible assets, net					18		19
Noncurrent derivative instruments					2		211
Other assets					112		108
	Total assets			$	26,168	$	26,294
Liabilities and Stockholders’ Equity
Current liabilities:
	Accounts payable - trade			$	61	$	50
	Bank overdrafts				105		159
	Revenue payable				258		253
	Accrued drilling costs				605		574
	Derivative instruments				292		-
	Other current liabilities				339		320
			Total current liabilities		1,660		1,356
Long-term debt					4,567		4,194
Deferred income taxes					1,612		1,808
Noncurrent derivative instruments					75		-
Asset retirement obligations and other long-term liabilities					195		168
Commitments and contingencies (Note 9)
Stockholders’ equity:
	Common stock, $0.001 par value; 300,000,000 authorized; 201,755,333 and
		201,288,884 shares issued at March 31, 2019 and December 31, 2018,
		respectively			-		-
	Additional paid-in capital				14,797		14,773
	Retained earnings				3,406		4,126
	Treasury stock, at cost; 1,155,813 and 1,031,655 shares at March 31, 2019 and
		December 31, 2018, respectively			(144)		(131)
			Total stockholders’ equity		18,059		18,768
	Total liabilities and stockholders’ equity			$	26,168	$	26,294
The accompanying notes are an integral part of these consolidated financial statements.

1

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited

			Three Months Ended
			March 31,
(in millions, except per share amounts)				2019		2018
Operating revenues:
	Oil sales		$	935	$	793
	Natural gas sales			169		154
		Total operating revenues		1,104		947
Operating costs and expenses:
	Oil and natural gas production			174		130
	Production and ad valorem taxes			86		70
	Gathering, processing and transportation			26		11
	Exploration and abandonments			47		18
	Depreciation, depletion and amortization			465		317
	Accretion of discount on asset retirement obligations			3		2
	General and administrative (including non-cash stock-based compensation of $24 and
		$17 for the three months ended March 31, 2019 and 2018, respectively)		91		65
	Loss on derivatives			1,059		35
	Gain on disposition of assets, net			(1)		(723)
	Transaction costs			-		7
		Total operating costs and expenses		1,950		(68)
Income (loss) from operations				(846)		1,015
Other income (expense):
	Interest expense			(47)		(30)
	Other, net			4		104
		Total other income (expense)		(43)		74
Income (loss) before income taxes				(889)		1,089
	Income tax (expense) benefit			194		(254)
Net income (loss)			$	(695)	$	835
Earnings per share:
	Basic net income (loss)		$	(3.49)	$	5.60
	Diluted net income (loss)		$	(3.49)	$	5.58
The accompanying notes are an integral part of these consolidated financial statements.

2

Concho Resources Inc.

Consolidated Statements of Stockholders’ Equity

Unaudited

			Common Stock			Additional								Total
			Issued			Paid-in		Retained			Treasury Stock			Stockholders’
(in millions, except share data)			Shares	Amount		Capital		Earnings			Shares	Amount		Equity
		(in thousands)								(in thousands)
BALANCE AT DECEMBER 31, 2017			149,325	$	-	$	7,142	$	1,840		598	$	(67)	$	8,915
	Net income		-		-		-		835		-		-		835
	Grants of restricted stock		112		-		-		-		-		-		-
	Performance unit share conversion		446		-		-		-		-		-		-
	Cancellation of restricted stock		(13)		-		-		-		-		-		-
	Stock-based compensation		-		-		17		-		-		-		17
	Purchase of treasury stock		-		-		-		-		202		(29)		(29)
BALANCE AT MARCH 31, 2018			149,870	$	-	$	7,159	$	2,675		800	$	(96)	$	9,738
BALANCE AT DECEMBER 31, 2018			201,289	$	-	$	14,773	$	4,126		1,032	$	(131)	$	18,768
	Net loss		-		-		-		(695)		-		-		(695)
	Common stock dividends ($0.125 per share)		-		-		-		(25)		-		-		(25)
	Grants of restricted stock		235		-		-		-		-		-		-
	Performance unit share conversion		246		-		-		-		-		-		-
	Cancellation of restricted stock		(15)		-		-		-		-		-		-
	Stock-based compensation		-		-		24		-		-		-		24
	Purchase of treasury stock		-		-		-		-		124		(13)		(13)
BALANCE AT MARCH 31, 2019			201,755	$	-	$	14,797	$	3,406		1,156	$	(144)	$	18,059
The accompanying notes are an integral part of these consolidated financial statements.

3

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited

					Three Months Ended
					March 31,
(in millions)					2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income (loss)				$	(695)	$	835
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Depreciation, depletion and amortization				465		317
		Accretion of discount on asset retirement obligations				3		2
		Exploration and abandonments				38		10
		Non-cash stock-based compensation expense				24		17
		Deferred income taxes				(194)		254
		Gain on disposition of assets, net				(1)		(723)
		Loss on derivatives				1,059		35
		Net settlements paid on derivatives				-		(112)
		Other				2		(96)
	Changes in operating assets and liabilities, net of acquisitions and dispositions:
			Accounts receivable			(111)		(81)
			Prepaid costs and other			9		(2)
			Inventory			-		3
			Accounts payable			11		(12)
			Revenue payable			8		2
			Other current liabilities			5		39
				Net cash provided by operating activities		623		488
CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to oil and natural gas properties					(885)		(474)
	Acquisitions of oil and natural gas properties					(5)		(13)
	Additions to property, equipment and other assets					(15)		(6)
	Proceeds from the disposition of assets					5		255
	Direct transaction costs for disposition of assets					(2)		(3)
	Distribution from equity method investment					-		148
				Net cash used in investing activities		(902)		(93)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Borrowings under credit facility					1,112		662
	Payments on credit facility					(739)		(984)
	Payment of common stock dividends					(25)		-
	Purchases of treasury stock					(13)		(29)
	Decrease in bank overdrafts					(54)		(44)
	Other					(2)		-
				Net cash provided by (used in) financing activities		279		(395)
				Net increase in cash and cash equivalents		-		-
Cash and cash equivalents at beginning of period						-		-
Cash and cash equivalents at end of period					$	-	$	-
The accompanying notes are an integral part of these consolidated financial statements.

4

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Note 1. Organization and nature of operations

Concho Resources Inc. (the “Company”) is a Delaware corporation formed on February 22, 2006. The Company’s principal business is the acquisition, development, 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.

 At March 31, 2019, the Company owned a 23.75 percent membership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering and transportation system in the Delaware Basin. 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 remaining distribution of approximately $103 million was recorded in other income (expense) on the Company’s consolidated statement of operations since the lenders to the term loan do not have recourse against the Company, and the Company has no contractual obligation to repay the distribution.

5

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

The Company’s net investment in Oryx was zero at March 31, 2019 and December 31, 2018. The Company did not record income or loss on the Oryx investment for the three months ended March 31, 2019, as cumulative net income had yet to exceed the distribution in excess of the Company’s investment. In April 2019, Oryx entered into an agreement to sell 100 percent of its equity interests, which included the Company’s 23.75 percent membership interest.

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 March 31, 2019 and December 31, 2018, the Company had receivables related to contracts with customers of approximately $530 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 as they represent payment for services performed outside of the contract with the customer.

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 costs, 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.

6

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

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 expense. Such fees totaled approximately $4 million for each of the three months ended March 31, 2019 and 2018.

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 does not currently 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 approximately $19 million and $16 million relate to the Company’s operating and finance leases, respectively, and approximately $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. The 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.

7

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

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 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 is currently assessing the effect that ASU 2018-18 will have on its financial position, results of operations and disclosures.    

8

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

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 preliminary 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			124
	Long-term debt			1,758
	Deferred income taxes			514
	Asset retirement obligations			20
	Noncurrent derivative instruments			5
		Total liabilities assumed	$	2,558
		Total purchase price plus liabilities assumed	$	10,107
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			2,229
		Total assets acquired	$	10,107

9

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Pro forma data. The following unaudited pro forma combined condensed financial data for the three months ended March 31, 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.

		Three Months Ended
(in millions, except per share amounts)		March 31, 2018
Operating revenues		$	1,226
Net income		$	931
Earnings per share:
	Basic net income	$	4.66
	Diluted net income	$	4.64

10

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Note 4. Other acquisitions, divestitures and nonmonetary transactions

During the three months ended March 31, 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 three months ended March 31, 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 three months ended March 31, 2018. The assets divested included proved and unproved oil and natural gas properties on approximately 20,000 net acres.

Nonmonetary transactions. During the three months ended March 31, 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 $14 million, included in gain on disposition of assets, net on the Company’s consolidated statement of operations for the three months ended March 31, 2018.

11

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Note 5.Stock incentive plan

The Company’s 2015 Stock Incentive Plan (“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. At the end of each performance period, each performance unit award 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. The total number of units converted to restricted stock awards will depend on the Company’s performance at the end of each performance period. All other performance unit awards have 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 three months ended March 31, 2019 is presented below:

		Restricted			Performance
		Stock Shares			Units
Outstanding at December 31, 2018			1,364,699		218,391
	Awards granted (a)		235,082		212,947	(b)
	Awards cancelled / forfeited		(14,947)		-
	Lapse of restrictions		(146,048)		-
Outstanding at March 31, 2019		1,438,786		431,338
(a)	Weighted average grant date fair value per share/unit	$	105.52	$	144.03
(b)	Includes 38,952 performance award units 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 March 31, 2019:

(in millions)
Remaining 2019		$	61
2020			48
2021			22
2022			4
2023			2
2024			1
Thereafter			2
	Total	$	140

12

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

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.

13

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 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 March 31, 2019 and December 31, 2018:

			March 31, 2019				December 31, 2018
			Carrying		Fair		Carrying		Fair
(in millions)			Value		Value		Value		Value
Assets:
		Derivative instruments	$	3	$	3	$	695	$	695
Liabilities:
		Derivative instruments	$	367	$	367	$	-	$	-
		Credit facility	$	615	$	615	$	242	$	242
		$600 million 4.375% senior notes due 2025 (a)	$	594	$	617	$	594	$	591
		$1,000 million 3.75% senior notes due 2027 (a)	$	989	$	991	$	989	$	939
		$1,000 million 4.3% senior notes due 2028 (a)	$	988	$	1,033	$	988	$	980
		$800 million 4.875% senior notes due 2047 (a)	$	789	$	849	$	789	$	761
		$600 million 4.85% senior notes due 2048 (a)	$	592	$	634	$	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.

14

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

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

March 31, 2019
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable		Total		Consolidated		Consolidated
				Assets				Inputs		Inputs		Fair		Balance		Balance
(in millions)				(Level 1)				(Level 2)		(Level 3)		Value		Sheet		Sheet
	Assets:
		Current:
			Commodity derivatives		$	-	$	57	$	-	$	57	$	(56)	$	1
		Noncurrent:
			Commodity derivatives			-		29		-		29		(27)		2
	Liabilities:
		Current:
			Commodity derivatives			-		(348)		-		(348)		56		(292)
		Noncurrent:
			Commodity derivatives			-		(102)		-		(102)		27		(75)
	Net derivative instruments				$	-	$	(364)	$	-	$	(364)	$	-	$	(364)

15

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

December 31, 2018
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable		Total		Consolidated		Consolidated
				Assets				Inputs		Inputs		Fair		Balance		Balance
(in millions)				(Level 1)				(Level 2)		(Level 3)		Value		Sheet		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 March 31, 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.

16

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Note 7. Derivative financial instruments

The Company uses derivative financial instruments to manage its exposure to commodity price fluctuations. Commodity derivative instruments are used to (i) reduce the effect of the volatility of price changes on the oil and natural gas the Company produces and sells, (ii) support the Company’s capital budget and expenditure plans and (iii) support the economics associated with acquisitions. The Company does not enter into derivative financial instruments for speculative or trading purposes. The Company 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 months ended March 31, 2019 and 2018:

			Three Months Ended
			March 31,
(in millions)				2019		2018
Loss on derivatives:
	Oil derivatives		$	(1,056)	$	(33)
	Natural gas derivatives			(3)		(2)
		Total	$	(1,059)	$	(35)
The following table represents the Company’s net cash receipts from (payments on) derivatives for the three months ended March 31, 2019 and 2018:
			Three Months Ended
			March 31,
(in millions)				2019		2018
Net cash receipts from (payments on) derivatives:
	Oil derivatives		$	3	$	(113)
	Natural gas derivatives			(3)		1
		Total	$	-	$	(112)

17

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

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

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Price Swaps: (a)
	2019:
		Volume (Bbl)		-		15,112,750		13,378,000		11,232,000		39,722,750
		Price per Bbl	$	-	$	56.59	$	56.41	$	55.88	$	56.33
	2020:
		Volume (Bbl)		10,502,500		10,166,500		9,453,000		9,218,000		39,340,000
		Price per Bbl	$	57.28	$	57.24	$	57.18	$	57.14	$	57.21
	2021:
		Volume (Bbl)		2,160,000		2,184,000		2,024,000		2,024,000		8,392,000
		Price per Bbl	$	54.57	$	54.57	$	54.50	$	54.50	$	54.54
Oil Costless Collars: (a)
	2019:
		Volume (Bbl)		-		1,213,250		1,135,000		1,058,000		3,406,250
		Ceiling price per Bbl	$	-	$	64.00	$	63.47	$	62.95	$	63.50
		Floor price per Bbl	$	-	$	56.06	$	55.74	$	55.43	$	55.76
Oil Basis Swaps: (b)
	2019:
		Volume (Bbl)		-		11,965,500		12,650,000		15,133,000		39,748,500
		Price per Bbl	$	-	$	(3.03)	$	(2.82)	$	(2.32)	$	(2.69)
	2020:
		Volume (Bbl)		13,013,000		10,192,000		10,120,000		10,120,000		43,445,000
		Price per Bbl	$	(0.53)	$	(0.70)	$	(0.71)	$	(0.71)	$	(0.65)
	2021:
		Volume (Bbl)		2,070,000		2,093,000		2,116,000		2,116,000		8,395,000
		Price per Bbl	$	0.55	$	0.55	$	0.55	$	0.55	$	0.55
Natural Gas Price Swaps: (c)
	2019:
		Volume (MMBtu)		-		17,241,387		17,298,537		17,209,535		51,749,459
		Price per MMBtu	$	-	$	2.87	$	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.

18

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Note 8. Debt 

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

				March 31,		December 31,
(in millions)				2019		2018
Credit facility due 2022			$	615	$	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				(38)		(38)
	Less: current portion			-		-
		Total long-term debt	$	4,567	$	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 March 31, 2019, the Company’s commitments from its bank group were $2.0 billion, of which $1.4 billion was unused commitments, net of letters of credit. During the three months ended March 31, 2019, the weighted average interest rate on the Credit Facility was 4.4 percent.At March 31, 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 March 31, 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 months ended March 31, 2019 and 2018:

		Three Months Ended
		March 31,
(in millions)			2019		2018
Cash payments for interest		$	63	$	18
Non-cash interest			1		1
Net changes in accruals			(13)		12
	Interest costs incurred		51		31
Less: capitalized interest			(4)		(1)
	Total interest expense	$	47	$	30

19

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 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 March 31, 2019:

(in millions)
Remaining 2019		$	35
2020			75
2021			76
2022			36
2023			33
2024			34
Thereafter			96
	Total	$	385

20

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

At March 31, 2019, the Company’s delivery commitments covered the following gross volumes of oil and natural gas:

		Oil	Natural Gas
		(MMBbl)	(MMcf)
Remaining 2019		12	2,697
2020		36	10,286
2021		39	21,627
2022		41	16,425
2023		33	16,425
2024		33	16,470
Thereafter		114	32,850
	Total	308	116,780

Other commitments.In May 2018, the Company entered into a one-year term oil marketing contract with a third-party purchaser. The contract requires the Company to deliver not less than seven thousand barrels per day. Should there be a delivery shortfall in any given month, the Company retains an option to deliver the shortfall volume in any two subsequent months; however, failure to meet this volume delivery commitment would result in a penalty equal to the volume shortfall multiplied by the then market price for oil. If production is not sufficient to meet the sales commitment, the Company may purchase commodities in the market to satisfy its commitment.

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 startup of Cactus II Pipeline system 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. 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 March 31, 2019:

(in millions)		Classification	March 31, 2019
Assets
Operating lease right-of-use assets		Other property and equipment, net	$	18
Finance lease right-of-use assets		Other property and equipment, net		15
Total lease right-of-use assets (a)			$	33
Liabilities
Current:
Operating		Other current liabilities	$	7
Finance		Other current liabilities		6
Noncurrent:
Operating		Asset retirement obligations and other long-term liabilities		13
Finance		Asset retirement obligations and other long-term liabilities		10
Total lease liabilities (a)			$	36
(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.

21

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

The following table provides the components of lease cost, excluding lease cost related to short-term leases, for the three months ended March 31, 2019:

			Three Months Ended
(in millions)		Classification	March 31, 2019
Operating lease cost		General and administrative	$	2
Finance lease cost		Depreciation, depletion, and amortization (a)		2
Total lease cost			$	4
(a)	Interest on lease liabilities related to finance leases was immaterial during the three months ended March 31, 2019.

The Company’s short-term leases are comprised primarily of drilling rigs and certain field equipment. During the three months ended March 31, 2019, the Company’s gross lease cost related to its short-term leases was $94 million, of which $67 million was 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 three months ended March 31, 2019:

		Three Months Ended
(in millions)		March 31, 2019
Cash paid for amounts included in measurement of lease liabilities:
Operating cash flows from operating leases	$	2
Financing cash flows from finance leases	$	2
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	-
Finance leases	$	3

The following table provides lease terms and discount rates related to leases at March 31, 2019:

	March 31, 2019
Weighted average remaining lease term (years):
Operating leases		3.5
Finance leases		2.9
Weighted average discount rate:
Operating leases		4.9%
Finance leases		4.4%

22

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

The following table provides maturities of lease liabilities at March 31, 2019:

(in millions)		Operating Leases		Finance Leases
Remaining 2019	$	6	$	5
2020		8		6
2021		6		4
2022		1		2
Thereafter		1		-
Total lease payments		22		17
Less: interest		(2)		(1)
Present value of lease liabilities	$	20	$	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 for the three months ended March 31, 2018. 

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

23

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

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 March 31, 2019 and 2018, the Company recorded an income tax benefit of approximately $194 million and an income tax expense of approximately $254 million, respectively. The change is primarily due to the pre-tax loss for the three months ended March 31, 2019 as compared to the pre-tax income for the three months ended March 31, 2018.

The effective income tax rates were 22 percent and 23 percent for the three months ended March 31, 2019 and 2018, respectively.

The difference between the Company’s effective tax rates for the three months ended March 31, 2019 as compared to 2018 is primarily due to the research and development credit, net of unrecognized tax benefits, partially offset by the impact of other items. The Company recorded a discrete income tax benefit related to stock-based awards of approximately $2 million for each of the three months ended March 31, 2019 and 2018.

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 March 31, 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 partnership interest.

At March 31, 2019, the Company had an ownership interest in an entity that operates and manages various water infrastructure assets located in the Permian Basin and accounts for this investment using the equity method. The Company also has a water management services agreement with this entity under which the Company pays a fee for each barrel of produced water.

The payments to the Company’s related parties totaled approximately $6 million and $1 million for the three months ended March 31, 2019 and 2018, respectively.

24

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

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 months ended March 31, 2019 and 2018, respectively, under the two-class method:

			Three Months Ended
			March 31,
(in millions)			2019		2018
Net income (loss) as reported			$	(695)	$	835
Participating basic earnings (a)				-		(6)
	Basic earnings (loss) attributable to common stockholders			(695)		829
Reallocation of participating earnings				-		-
	Diluted earnings (loss) attributable to common stockholders		$	(695)	$	829
(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.

25

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three months ended March 31, 2019 and 2018:

			Three Months Ended
			March 31,
(in thousands)			2019	2018
Weighted average common shares outstanding:
	Basic		199,148	147,925
		Dilutive performance units	-	537
	Diluted		199,148	148,462

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
		March 31,
(in thousands)		2019	2018
Number of antidilutive units:
	Performance units	324	-

Performance unit awards. The number of shares of common stock that will ultimately be issued for performance units will be determined by a combination of (i) comparing the Company’s total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. The performance period 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.

26

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Note 13. Subsidiary guarantors

At March 31, 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 March 31, 2019 and December 31, 2018, condensed consolidating statements of operations for the three  months ended March 31, 2019 and 2018 and condensed consolidating statements of cash flows for the three  months ended March 31, 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.

27

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Condensed Consolidating Balance Sheet
March 31, 2019
			Parent	Subsidiary			Subsidiary		Consolidating
(in millions)			Issuer	Guarantors		Non-Guarantor			Entries		Total
ASSETS
Accounts receivable - related parties		$	18,518	$	-	$	-	$	(18,518)	$	-
Other current assets			6		1,021		-		-		1,027
Oil and natural gas properties, net			-		22,405		16		-		22,421
Property and equipment, net			-		350		-		-		350
Investment in subsidiaries			5,629		-		-		(5,629)		-
Goodwill			-		2,229		-		-		2,229
Other long-term assets			15		126		-		-		141
	Total assets	$	24,168	$	26,131	$	16	$	(24,147)	$	26,168
LIABILITIES AND EQUITY
Accounts payable - related parties		$	-	$	18,502	$	16	$	(18,518)	$	-
Other current liabilities			368		1,292		-		-		1,660
Long-term debt			4,567		-		-		-		4,567
Other long-term liabilities			1,174		708		-		-		1,882
Equity			18,059		5,629		-		(5,629)		18,059
	Total liabilities and equity	$	24,168	$	26,131	$	16	$	(24,147)	$	26,168

Condensed Consolidating Balance Sheet
December 31, 2018
			Parent	Subsidiary			Subsidiary	Consolidating
(in millions)			Issuer	Guarantors		Non-Guarantor			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

28

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2019
			Parent		Subsidiary		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Non-Guarantor		Entries		Total
Total operating revenues		$	-	$	1,104	$	-	$	-	$	1,104
Total operating costs and expenses			(1,060)		(890)		-		-		(1,950)
	Income (loss) from operations		(1,060)		214		-		-		(846)
Interest expense			(47)		-		-		-		(47)
Other, net			218		4		-		(218)		4
	Income (loss) before income taxes		(889)		218		-		(218)		(889)
Income tax benefit			194		-		-		-		194
	Net income (loss)	$	(695)	$	218	$	-	$	(218)	$	(695)

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2018
			Parent		Subsidiary		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Non-Guarantors		Entries		Total
Total operating revenues		$	-	$	942	$	5	$	-	$	947
Total operating costs and expenses			(34)		105		(3)		-		68
	Income (loss) from operations		(34)		1,047		2		-		1,015
Interest expense			(30)		-		-		-		(30)
Other, net			1,153		104		-		(1,153)		104
	Income before income taxes		1,089		1,151		2		(1,153)		1,089
Income tax expense			(254)		-		-		-		(254)
	Net income	$	835	$	1,151	$	2	$	(1,153)	$	835

29

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2019
		Parent		Subsidiary		Subsidiary			Consolidating
(in millions)		Issuer		Guarantors		Non-Guarantor			Entries			Total
Net cash flows provided by (used in) operating activities		$	(335)	$	958		$	-	$	-	$	623
Net cash flows used in investing activities			-		(902)			-		-		(902)
Net cash flows provided by (used in) financing activities			335		(56)			-		-		279
	Net increase 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
Three Months Ended March 31, 2018
		Parent		Subsidiary		Subsidiary			Consolidating
(in millions)		Issuer		Guarantors		Non-Guarantor			Entries			Total
Net cash flows provided by operating activities		$	351	$	137		$	-	$	-	$	488
Net cash flows used in investing activities			-		(93)			-		-		(93)
Net cash flows used in financing activities			(351)		(44)			-		-		(395)
	Net increase in cash and cash equivalents		-		-			-		-		-
	Cash and cash equivalents at beginning of period		-		-			-		-		-
	Cash and cash equivalents at end of period	$	-	$	-		$	-	$	-	$	-

30

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Note 14. Subsequent events

Oryx divestiture.In April 2019, Oryx entered into an agreement to sell 100 percent of its equity interests. The Company expects to receive approximately $300 million, net of closing costs, for its 23.75 percent membership interest.

Midstream joint venture.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.

2019 dividends. On April 30, 2019, the Company’s board of directors approved a cash dividend of $0.125 per share for the second quarter of 2019 that is expected to be paid on June 28, 2019 to stockholders of record as of May 10, 2019.

New commodity derivative contracts.After March 31, 2019, the Company entered into the following derivative contracts to hedge additional amounts of estimated future production:

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Price Swaps: (a)
	2019:
		Volume (Bbl)		-		1,707,000		1,451,000		1,281,000		4,439,000
		Price per Bbl	$	-	$	62.64	$	63.14	$	63.43	$	63.03
	2021:
		Volume (Bbl)		1,170,000		1,183,000		1,196,000		1,196,000		4,745,000
		Price per Bbl	$	56.72	$	56.72	$	56.72	$	56.72	$	56.72
Oil Basis Swaps: (b)
	2019:
		Volume (Bbl)		-		-		92,000		920,000		1,012,000
		Price per Bbl	$	-	$	-	$	(1.05)	$	(0.07)	$	(0.16)
	2020:
		Volume (Bbl)		1,092,000		-		-		-		1,092,000
		Price per Bbl	$	0.10	$	-	$	-	$	-	$	0.10
	2021:
		Volume (Bbl)		540,000		546,000		552,000		552,000		2,190,000
		Price per Bbl	$	0.50	$	0.50	$	0.50	$	0.50	$	0.50
(a)	The oil derivative contracts are settled based on the NYMEX – WTI calendar-month average futures price.
(b)	The basis differential price is between Midland – WTI and Cushing – WTI. These contracts are settled on a calendar-month basis.

31

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Note 15. Supplementary information

Capitalized costs

			March 31,		December 31,
(in millions)			2019		2018
Oil and natural gas properties:
	Proved		$	26,000	$	24,992
	Unproved			6,559		6,714
	Less: accumulated depletion			(10,138)		(9,701)
		Net capitalized costs for oil and natural gas properties	$	22,421	$	22,005

Costs incurred for oil and natural gas producing activities

		Three Months Ended
		March 31,
(in millions)		2019		2018
Property acquisition costs:
	Proved	$	-	$	-
	Unproved		4		13
Exploration			462		243
Development			464		207
	Total costs incurred for oil and natural gas properties	$	930	$	463

32

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 three months ended March 31, 2019 and 2018 included the following highlights:

·Net loss was $695 million ($(3.49)per diluted share) as compared to net income of $835 million ($5.58per diluted share) for the first three months of 2019 and 2018, respectively. The decrease in net income was primarily due to:

•$1,024 million increase in loss on derivatives due to a $1,059 million loss on derivatives during the three months ended March 31, 2019, as compared to a loss of $35 million during 2018;

•$722 million net decrease in gain on disposition of assets related to a gain of approximately $723 million, primarily due to certain acquisitions and divestitures during 2018, as discussed in Note 4 of the Condensed Notes to Consolidated Financial Statements;

•$148 million increase in depreciation, depletion and amortization expense, primarily due to an increase in production and the depletion rate per Boe;

•$100 million decrease in other income, primarily due to a gain of approximately $103 million during the three months ended March 31, 2018 on the equity method investment distribution received from Oryx Southern Delaware Holdings, LLC (“Oryx”); and

•$44 million increase in production expense, primarily due to increased production and activities associated with the additional wells successfully drilled and completed in 2018 and 2019 as well as our acquisitions during 2018;

partially offset by:

•$157 million increase in oil and natural gas revenues as a result of a 44percent increase in production, partially offset by a 19 percent decrease in commodity price realizations per Boe (excluding the effects of derivative activities).

·Average daily sales volumes of 328 MBoe per day during the first three months of 2019 increased 44 percent as compared to 228 MBoe per day during 2018.

·Net cash provided by operating activities increased by approximately $135 million to $623 million for the first three months of 2019, as compared to $488 million in the first three months of 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.

33

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

34

derivative positions at March 31, 2019 and additional derivative contracts entered into subsequent to March 31, 2019, respectively.

The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three months ended March 31, 2019 and 2018, as well as the high and low NYMEX prices for the same periods:

			Three Months Ended
			March 31,
			2019		2018
Average NYMEX prices:
	Oil (Bbl)		$	54.87	$	62.96
	Natural gas (MMBtu)		$	2.88	$	2.84
High and Low NYMEX prices:
	Oil (Bbl):
		High	$	60.14	$	66.14
		Low	$	45.41	$	59.19
	Natural gas (MMBtu):
		High	$	3.59	$	3.63
		Low	$	2.55	$	2.55

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $66.30 and $61.59 per Bbl and $2.71 and $2.46 per MMBtu, respectively, during the period from April 1, 2019 to April 29, 2019. At April 29, 2019, the NYMEX oil price and NYMEX natural gas price were $63.50 per Bbl and $2.59 per MMBtu, respectively.

Historically, and during the three months ended March 31, 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 $24.13 per Bbl and $27.64 per Bbl during the three months ended March 31, 2019 and 2018, respectively.

35

Recent Events

Oryx divestiture.In April 2019, Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering and transportation system in the Delaware Basin, entered into an agreement to sell 100 percent of its equity interests. We expect to receive approximately $300 million, net of closing costs, for our 23.75 percent membership interest. We intend to use the proceeds of this sale 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.

2019 dividends. On February 19, 2019, our board of directors declared a cash dividend of $0.125 per share. The total cash dividend, including the cash dividend paid on unvested restricted stock awards, of $25 million was paid on March 29, 2019 to stockholders of record as of March 1, 2019. On April 30, 2019, our board of directors approved a cash dividend of $0.125 per share for the second quarter of 2019 that is expected to be paid on June 28, 2019 to stockholders of record as of May 10, 2019.

Derivative Financial Instruments

Derivative financial instrument exposure. At March 31, 2019, the fair value of our financial derivatives was a net liability of $364million. 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 March 31, 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 months ended March 31, 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
					March 31,
					2019		2018
Production and operating data:
	Net production volumes:
		Oil (MBbl)				18,936		12,939
		Natural gas (MMcf)				63,769		45,448
		Total (MBoe)				29,564		20,514
	Average daily production volumes:
		Oil (Bbl)				210,400		143,767
		Natural gas (Mcf)				708,544		504,978
		Total (Boe)				328,491		227,930
	Average prices per unit:
		Oil, without derivatives (Bbl)			$	49.39	$	61.29
		Oil, with derivatives (Bbl) (a)			$	49.56	$	52.59
		Natural gas, without derivatives (Mcf)			$	2.64	$	3.39
		Natural gas, with derivatives (Mcf) (a)			$	2.59	$	3.41
		Total, without derivatives (Boe)			$	37.33	$	46.17
		Total, with derivatives (Boe) (a)			$	37.34	$	40.71
	Operating costs and expenses per Boe: (b)
		Oil and natural gas production			$	5.87	$	6.33
		Production and ad valorem taxes			$	2.92	$	3.40
		Gathering, processing and transportation			$	0.88	$	0.53
		Depreciation, depletion and amortization			$	15.74	$	15.43
		General and administrative			$	3.08	$	3.31
	(a)	Includes the effect of net cash receipts from (payments on) derivatives:
					Three Months Ended
					March 31,
		(in millions)			2019		2018
		Net cash receipts from (payments on) derivatives:
			Oil derivatives		$	3	$	(113)
			Natural gas derivatives			(3)		1
				Total	$	-	$	(112)
		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.
	(b)	Per Boe amounts calculated using dollars and volumes rounded to thousands.

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Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018

Oil and natural gas revenues.  Revenue from oil and natural gas operations was$1,104 million for the three months ended March 31, 2019, an increase of$157 million (17 percent) from $947 million for 2018. This increase was primarily due to the increase in oil and natural gas production, in part due to an increase in non-operated revenues, 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:

·total oil production was 18,936 MBbl for the three months ended March 31, 2019, an increase  of 5,997 MBbl  (46 percent) from 12,939 MBbl  for 2018; 

·average realized oil price (excluding the effects of derivative activities) was $49.39 per Bbl during the three months ended March 31, 2019, a decrease of 19 percent  from $61.29  per Bbl during 2018. For the three months ended March 31, 2019, our crude oil price differential relative to NYMEX was $(5.48) per Bbl, or a realization of approximately 90 percent, as compared to a crude oil price differential relative to NYMEX of $(1.67) per Bbl, or a realization of approximately 97 percent, for 2018. 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 March 31, 2019 and 2018, the average market Mid-Cush differential was a price reduction of $3.86 per Bbl and a price benefit of $0.38  per Bbl, respectively. The Mid-Cush differential significantly narrowed in March 2019 and into the second quarter of 2019, although it is possible that the differential could widen again at certain times during 2019;

·total natural gas production was 63,769 MMcf for the three months ended March 31, 2019, an increase  of 18,321 MMcf  (40 percent) from 45,448 MMcf  for 2018; and

·average realized natural gas price (excluding the effects of derivative activities) was $2.64 per Mcf during the three months ended March 31, 2019, a decrease of 22 percent  from $3.39 per Mcf during 2018. For the three months ended March 31, 2019 and 2018, we realized approximately 92 percent and 119 percent, respectively, of the average NYMEX natural gas prices for the respective periods. 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 natural gas takeaway in the Permian Basin, the price differential for natural gas residue increased significantly, and could increase again at certain times during 2019. These widening natural gas residue differentials negatively impacted our realized natural gas prices during the three months ended March 31, 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 92 percent of the average NYMEX natural gas price, which falls below our historical amounts. In addition, the average Mont Belvieu price for a blended barrel of natural gas liquids decreased from $27.64 per Bbl during the three months ended 2018 to $24.13 per Bbl during the three months ended March 31, 2019.

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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 months ended March 31, 2019 and 2018:

			Three Months Ended March 31,
			2019				2018
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe
Lease operating expenses		$	166	$	5.59	$	121	$	5.88
Workover costs			8		0.28		9		0.45
	Total oil and natural gas production expenses	$	174	$	5.87	$	130	$	6.33

Lease operating expenses were $166 million ($5.59 per Boe) for the three months ended March 31, 2019, which was an increase of $45 million from $121 million ($5.88 per Boe) during 2018. The increase in lease operating expenses during the first quarter of 2019 as compared to 2018 was primarily the result of (i) additional wells successfully drilled and completed and (ii) our acquisitions during 2018, primarily the RSP Acquisition. The decrease in lease operating expenses per Boe was primarily due to increased production.

Workover costs were $8 million ($0.28 per Boe) for the three months ended March 31, 2019, which was a decrease of $1 million from $9 million ($0.45 per Boe) during 2018. The decrease in workover costs during the first quarter of 2019 as compared to 2018 was primarily due to decreased workover activity. The decrease in workover costs per Boe was primarily due to the decrease in workover costs along with an increase in production.

Production and ad valorem taxes.  The following table provides the components of our production and ad valorem tax expenses for the three months ended March 31, 2019 and 2018:

			Three Months Ended March 31,
			2019				2018
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe
Production taxes		$	70	$	2.38	$	64	$	3.13
Ad valorem taxes			16		0.54		6		0.27
	Total production and ad valorem taxes	$	86	$	2.92	$	70	$	3.40

Production taxes per unit of production were $2.38 per Boe during the three months ended March 31, 2019, a decrease of 24 percent from $3.13 per Boe during 2018. Over the same period, our revenue per Boe (excluding the effects of derivatives) decreased 19 percent. 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. Ad valorem taxes increased by $10 million 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. 

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Gathering, processing and transportation costs.  The following table shows the gathering, processing and transportation costs for the three months ended March 31, 2019: 

		Three Months Ended March 31,
		2019				2018
			Per				Per
(in millions, except per unit amounts)	Amount		Boe		Amount		Boe
Gathering, processing and transportation costs	$	26	$	0.88	$	11	$	0.53

Gathering, processing and transportation costs were $26 million ($0.88 per Boe) for the three months ended March 31, 2019, an increase of 136 percent from $11 million ($0.53 per Boe) during 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 months ended March 31, 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 this 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 months ended March 31, 2019 and 2018:

		Three Months Ended
		March 31,
(in millions)		2019		2018
Geological and geophysical		$	6	$	5
Leasehold abandonments			30		10
Other			11		3
	Total exploration and abandonments	$	47	$	18

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.

For the three months ended March 31, 2019 and 2018, we recorded approximately $30 million and $10 million, respectively, of leasehold abandonments, 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 was primarily due to the abandonment of one exploratory well during the three months ended March 31, 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 months ended March 31, 2019 and 2018:

		Three Months Ended March 31,
		2019				2018
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties		$	457	$	15.47	$	311	$	15.13
Depreciation of other property and equipment			7		0.24		5		0.26
Amortization of intangible assets			1		0.03		1		0.04
	Total depletion, depreciation and amortization	$	465	$	15.74	$	317	$	15.43
Oil price used to estimate proved oil reserves at period end		$	59.52			$	49.94
Natural gas price used to estimate proved natural gas reserves at period end		$	3.07			$	3.00

Depletion of proved oil and natural gas properties was $457 million ($15.47 per Boe) for the three months ended March 31, 2019, an increase of $146 million (47 percent) from $311 million ($15.13 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.

General and administrative expenses.The following table provides components of our general and administrative expenses for the three months ended March 31, 2019 and 2018:

		Three Months Ended March 31,
		2019				2018
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe
General and administrative expenses		$	71	$	2.40	$	52	$	2.68
Less: Operating fee reimbursements			(4)		(0.13)		(4)		(0.21)
Non-cash stock-based compensation			24		0.81		17		0.84
	Total general and administrative expenses	$	91	$	3.08	$	65	$	3.31

Total general and administrative expenses were approximately $91 million ($3.08 per Boe) for the three months ended March 31, 2019, an increase of $26 million (40 percent) from $65 million ($3.31 per Boe) for 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 approximately $4 million for each of the three months ended March 31, 2019 and 2018. 

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Loss on derivatives.The following table sets forth the loss on derivatives for the three months ended March 31, 2019 and 2018:

			Three Months Ended
			March 31,
(in millions)				2019		2018
Loss on derivatives:
	Oil derivatives		$	(1,056)	$	(33)
	Natural gas derivatives			(3)		(2)
		Total	$	(1,059)	$	(35)
The following table represents our net cash receipts from (payments on) derivatives for the three months ended March 31, 2019 and 2018:
			Three Months Ended
			March 31,
(in millions)				2019		2018
Net cash receipts from (payments on) derivatives:
	Oil derivatives		$	3	$	(113)
	Natural gas derivatives			(3)		1
		Total	$	-	$	(112)

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 on disposition of assets, net. During the three months ended March 31, 2018, we recorded a net gain on disposition of assets of approximately $723 million due to (i) a non-cash gain of approximately $575 million related to our February 2018 acquisition and divestiture, (ii) a gain of approximately $134 million related to our January 2018 Delaware Basin divestitures and (iii) a gain of approximately $14 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.   

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Interest expense.  The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the three months ended March 31, 2019 and 2018:

		Three Months Ended
		March 31,
(in millions)		2019		2018
Interest expense, as reported		$	47	$	30
Capitalized interest			4		1
	Interest expense, excluding impact of capitalized interest	$	51	$	31
Weighted average interest rate - credit facility			4.4%		4.3%
Weighted average interest rate - senior notes			4.4%		4.3%
	Total weighted average interest rate		4.4%		4.3%
Weighted average credit facility balance		$	503	$	211
Weighted average senior notes balance			4,000		2,400
	Total weighted average debt balance	$	4,503	$	2,611

The increase in interest expense 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. 

Other income, net. During the three months ended March 31, 2018, we recorded other income of approximately $104 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 regarding this distribution.

Income tax provisions.  For the three months ended March 31, 2019, we recorded an income tax benefit of approximately $194 million compared to an income tax expense of approximately $254 million for the three months ended March 31, 2018. The change is primarily due to the pre-tax loss for the three months ended March 31, 2019 as compared to the pre-tax income for the three months ended March 31, 2018.

The effective income tax rates for the three months ended March 31, 2019 and 2018 were 22 percent and 23 percent, respectively. The change in our effective income tax rate was primarily due to the research and development credit, net of unrecognized tax benefits, partially offset by the impact of other items. We recorded a discrete income tax benefit related to stock-based awards of approximately $2 million for each of the three months ended March 31, 2019 and 2018.

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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 three months ended March 31, 2019 and 2018 totaled $926 million and $450 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 three months ended March 31, 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 February 19, 2019, our board of directors declared a cash dividend of $0.125 per share. The total cash dividend, including the cash dividend paid on unvested restricted stock awards, of $25 million was paid on March 29, 2019 to stockholders as of March 1, 2019. On April 30, 2019, our board of directors approved a cash dividend of $0.125 per share for the second quarter of 2019 that is expected to be paid on June 28, 2019 to stockholders of record as of May 10, 2019. 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.

Acquisitions. The following table reflects our expenditures for acquisitions of proved and unproved properties for the three months ended March 31, 2019 and 2018:

			Three Months Ended
			March 31,
(in millions)			2019		2018
Property acquisition costs:
	Proved		$	-	$	-
	Unproved			4		13
		Total property acquisition costs (a)	$	4	$	13
(a)	Included in the property acquisition costs above are budgeted unproved leasehold acreage acquisitions of approximately $4 million and $13 million for the three months ended March 31, 2019 and 2018, respectively.

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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:

·$373 million increase in long-term debt due to additional borrowings under our Credit Facility;

·$367 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 startup of Cactus II Pipeline system 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.

The following table summarizes our changes in cash and cash equivalents for the three months ended March 31, 2019 and 2018:

		Three Months Ended
		March 31,
(in millions)		2019		2018
Net cash provided by operating activities		$	623	$	488
Net cash used in investing activities			(902)		(93)
Net cash provided by (used in) financing activities			279		(395)
	Net increase in cash and cash equivalents	$	-	$	-

Cash flow from operating activities. The increase in operating cash flows during the three  months ended March 31, 2019 as compared to the same period in 2018 was primarily due to an increase in oil and natural gas revenues of $157 million and an increase of $112 million due to approximately zero net cash settlements on derivatives during the three months ended March 31, 2019, as compared to $112  million in settlements paid on derivatives during the comparable period in 2018. The increase was partially offset by a $44 million increase in production expense, a $19 million increase in cash general and administrative expense and a $16 million increase in production tax expense.

Our net cash provided by operating activities included a reduction of $78million and $51million for the three  months ended March 31, 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 three months ended March 31, 2019, our net cash used in investing activities was $902 million, which consisted primarily of our investment of $885 million for additions to oil and natural gas properties. Our capital expenditures for the three months ended March 31, 2019 were funded with cash flows from operations and borrowings under our Credit Facility.

During the three months ended March 31, 2018, our net cash used in investing activities was $93 million, which consisted primarily of our investment of $474 million for additions to oil and natural gas properties, partially offset by $255 million of proceeds received from asset dispositions and a distribution received from our equity method investment. We received a

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distribution from Oryx of $157 million during the three months ended March 31, 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 three months ended March 31, 2019, our net cash provided by financing activities was $279 million primarily due to $373 million of net borrowings under our Credit Facility partially offset by $25 million of dividends paid on our common stock. During the three months ended March 31, 2019, we decreased our bank overdraft by $54 million. For the three months ended March 31, 2018, our net cash used in financing activities was $395 million, primarily due to $322 million of net payments on our Credit Facility.

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 March 31, 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 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 March 31, 2019, our commitments from our bank group were $2.0 billion, of which $1.4 billion was 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 costs 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 March 31, 2019 was $22.7billion, consisting of debt of $4.6 billion and stockholders’ equity of $18.1 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 20 percent and 18  percent at March 31, 2019 and December 31, 2018, respectively. Our ratio of current assets to current liabilities was 0.62to 1.0 at March 31, 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.

Impairment of Long-Lived Assets

All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may be greater than management’s estimates of its future net cash flows, including cash flows from proved reserves, risk-adjusted probable and possible reserves, and integrated assets. If the carrying value of the long-lived assets exceeds the sum of estimated undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair value and the carrying value of the assets. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates, cash flows from integrated assets and other factors. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimated quantities of oil and natural gas reserves. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. At March 31, 2019, our 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 $60.36 per barrel of oil decreasing to a 2026 price of $53.52 per barrel of oil. Natural gas prices ranged from a 2019 price of $2.80 per Mcf of natural gas decreasing to a 2021 price of $2.65 per Mcf then rising to a 2026 price of $3.01 per Mcf of natural gas. Both oil and natural gas commodity prices for this purpose were held flat after 2026. We did not recognize an impairment charge during the three months ended March 31, 2019.

It is reasonably possible that the estimates of undiscounted future net cash flows of our long-lived assets may change in the future resulting in the need to impair carrying values. We estimate that if the future oil and natural gas prices used in this analysis, and noted above, would have been approximately 10 percent lower at March 31, 2019, with no other changes in capital costs, operating costs, price differentials or reserve performance curves, the carrying amount of our Yeso field would have exceeded the expected undiscounted future net cash flow, and an impairment of approximately $800 million would have been recorded. Other assumptions such as operating costs, well and reservoir performance, severance and ad valorem taxes and operating and development plans would likely change given a change in oil and natural gas prices. However, we did not estimate the correlation between these assumptions and any estimated commodity price change, and these and other assumptions may worsen or partially mitigate some of the effects of a reduction in commodity prices, including the ultimate impact and amount of any potential impairment charge. As a result, we are unable to predict with certainty whether or not a decline in commodity prices alone will or will not cause us to recognize an impairment charge in a particular field or the magnitude of any such impairment charge. We additionally note that there may be changes to both drilling and completion designs that affect the volume curves, capital costs estimates and the amount of proved undeveloped locations that can be recorded, each of which will affect management’s estimates of future cash flows.

Management’s judgments and estimates in all the areas listed above are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.

There have been no material changes in our critical accounting policies and procedures during the three months ended March 31, 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.

47

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.

48

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 March 31, 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 net income. The following table sets forth the hypothetical impact on the fair value of the commodity price risk management arrangements from an average increase and decrease in the commodity price of $5.00 per Bbl of oil and $0.50 per MMBtu of natural gas from the commodity prices at March 31, 2019:

				Increase of		Decrease of
				$5.00 per Bbl and		$5.00 per Bbl and
(in millions)				$0.50 per MMBtu		$0.50 per MMBtu
Gain (loss):
	Oil derivatives		$	(439)	$	439
	Natural gas derivatives			(35)		35
		Total	$	(474)	$	474

49

At March 31, 2019, we had (i) oil price swaps and oil costless collars covering future oil production from April 1, 2019 through December 31, 2021 and (ii) oil basis swaps covering our Midland to Cushing basis differential from April 1, 2019 to December 31, 2021. The NYMEX oil price at March 31, 2019 was $60.14 per Bbl. At April 29, 2019, the NYMEX oil price was $63.50 per Bbl.

At March 31, 2019, we had natural gas price swaps that settle on a monthly basis covering future natural gas production from April 1, 2019 to December 31, 2020. The NYMEX natural gas price at March 31, 2019 was $2.66 per MMBtu. At April 29, 2019, the NYMEX natural gas price was $2.59 per MMBtu.

A decrease in the average forward NYMEX oil and natural gas prices below those at March 31, 2019 would decrease the fair value liability of our commodity derivative contracts from their recorded balance at March 31, 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 March 31, 2019 would increase the fair value liability of our commodity derivative contracts from their recorded balance at March 31, 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.

We recorded a loss on derivatives of $1,059 million and $35 million for the three months ended March 31, 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 three months ended March 31, 2019. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the three months ended March 31, 2019:

		Commodity Derivative
		Instruments
(in millions)		Net Assets (Liabilities)
Fair value of contracts outstanding at December 31, 2018			$	695
	Changes in fair values (a)			(1,059)
	Contract maturities			-
Fair value of contracts outstanding at March 31, 2019 (b)			$	(364)
(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 $615 million outstanding under our Credit Facility at March 31, 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 $6 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 March 31, 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

In addition to the information set forth in this Quarterly Report, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2018, including those under the headings “Part I, Item 1. Business — Competition,” “— Marketing Arrangements” and “— Applicable Laws and Regulations,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” which risks could materially affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2018. The risks described in our reports filed with the SEC are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

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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
January 1, 2019 - January 31, 2019		123,306	$	104.35	-
February 1, 2019 - February 28, 2019		609	$	110.39	-
March 1, 2019 - March 31, 2019		243	$	108.44	-
(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.

53

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	**	Form of Performance Unit Award Agreement, dated January 2, 2019 (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.2	**	Form of Succession Restricted Stock Agreement, dated January 2, 2019 (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.3	**	Employment Agreement, dated January 1, 2019, by and between Concho Resources Inc. and J. Steve Guthrie (filed as Exhibit 10.8 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.4	**	Form of Indemnification Agreement, dated January 2, 2019, between Concho Resources Inc. and each of the officers and directors thereof (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.5	**	Form of Succession 3-Year Performance Unit Award Agreement, dated January 2, 2019, between Concho Resources Inc. and each of Messrs. Harper and Giraud (filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.6	**	Form of Succession 5-Year Performance Unit Award Agreement, dated January 2, 2019, between Concho Resources Inc. and each of Messrs. Harper and Giraud (filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.7	**	Executive Severance Plan, dated January 1, 2019, by and between Concho Resources Inc. and each of the officers thereof (filed as Exhibit 10.7 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.8	**	Form of Restricted Stock Agreement (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
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.
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.

54

(a) Filed herewith.

(b) Furnished herewith.

** Management contract or compensatory plan or arrangement.

55

SIGNATURES

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

CONCHO RESOURCES INC.
Date:	May 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)

56

EX-31

 

EXHIBIT 31.1

CERTIFICATIONS

I, Timothy A. Leach, certify that:

1.I have reviewed this quarterly report of Concho Resources Inc. (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 1, 2019	/s/  Timothy A. Leach
		Timothy A. Leach
		Chairman of the Board of Directors and Chief Executive Officer
		(Principal Executive Officer)

EX-31

 

EXHIBIT 31.2

CERTIFICATIONS

I, Brenda R. Schroer, certify that:

1.I have reviewed this quarterly report of Concho Resources Inc. (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 1, 2019	/s/  Brenda R. Schroer
		Brenda R. Schroer
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

EX-32

 

EXHIBIT 32.1

Certification of Chief Executive Officer of Concho Resources Inc.

(Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the quarterly report of Concho Resources Inc. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Timothy A. Leach, Chairman of the Board of Directors and Chief Executive Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 1, 2019	/s/  Timothy A. Leach
		Timothy A. Leach
		Chairman of the Board of Directors and Chief Executive Officer
		(Principal Executive Officer)

EX-32

 

EXHIBIT 32.2

Certification of Chief Financial Officer of Concho Resources Inc.

(Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the quarterly report of Concho Resources Inc. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Brenda R. Schroer, Senior Vice President, Chief Financial Officer and Treasurer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to her knowledge:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 1, 2019	/s/  Brenda R. Schroer
		Brenda R. Schroer
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	Apr. 29, 2019
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Trading Symbol	CXO
Entity Registrant Name	CONCHO RESOURCES INC
Entity Central Index Key	0001358071
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		200,594,025

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 0	$ 0
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas	530	466
Joint operations and other	413	365
Inventory	34	35
Derivative instruments	1	484
Prepaid costs and other	49	59
Total current assets	1,027	1,409
Property and equipment:
Oil and natural gas properties, successful efforts method	32,559	31,706
Accumulated depletion and depreciation	(10,138)	(9,701)
Total oil and natural gas properties, net	22,421	22,005
Other property and equipment, net	350	308
Total property and equipment, net	22,771	22,313
Deferred loan costs, net	9	10
Goodwill	2,229	2,224
Intangible assets, net	18	19
Noncurrent derivative instruments	2	211
Other assets	112	108
Total assets	26,168	26,294
Current liabilities:
Accounts payable - trade	61	50
Bank overdrafts	105	159
Revenue payable	258	253
Accrued drilling costs	605	574
Derivative instruments	292	0
Other current liabilities	339	320
Total current liabilities	1,660	1,356
Long-term debt	4,567	4,194
Deferred income taxes	1,612	1,808
Noncurrent derivative instruments	75	0
Asset retirement obligations and other long-term liabilities	195	168
Commitments and contingencies (Note 9)
Stockholders' equity:
Common stock, $0.001 par value; 300,000,000 authorized; 201,755,333 and 201,288,884 shares issued at March 31, 2019 and December 31, 2018, respectively	0	0
Additional paid-in capital	14,797	14,773
Retained earnings	3,406	4,126
Treasury stock, at cost; 1,155,813 and 1,031,655 shares at March 31, 2019 and December 31, 2018, respectively	(144)	(131)
Total stockholders' equity	18,059	18,768
Total liabilities and stockholders' equity	$ 26,168	$ 26,294

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	300,000,000	300,000,000
Common stock, shares issued	201,755,333	201,288,884
Treasury shares	1,155,813	1,031,655

XML

Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Operating revenues:
Total operating revenues	$ 1,104	$ 947
Operating costs and expenses:
Production and ad valorem taxes	86	70
Exploration and abandonments	47	18
Depreciation, depletion and amortization	465	317
Accretion of discount on asset retirement obligations	3	2
General and administrative (including non-cash stock-based compensation of $24 and $17 for the three months ended March 31, 2019 and 2018, respectively)	91	65
Loss on derivatives	1,059	35
Gain on disposition of assets, net	(1)	(723)
Transaction costs	0	7
Total operating costs and expenses	1,950	(68)
Income (loss) from operations	(846)	1,015
Other income (expense):
Interest expense	(47)	(30)
Other, net	4	104
Total other income (expense)	(43)	74
Income (loss) before income taxes	(889)	1,089
Income tax (expense) benefit	194	(254)
Net income (loss)	$ (695)	$ 835
Earnings per share:
Basic net income (loss)	$ (3.49)	$ 5.6
Diluted net income (loss)	$ (3.49)	$ 5.58
Oil [Member]
Operating revenues:
Total operating revenues	$ 935	$ 793
Natural Gas [Member]
Operating revenues:
Total operating revenues	169	154
Oil And Natural Gas Production [Member]
Operating costs and expenses:
Operating costs and expenses	174	130
Gathering, Processing and Transportation
Operating costs and expenses:
Operating costs and expenses	$ 26	$ 11

XML

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Income Statement [Abstract]
Non-cash stock-based compensation	$ 24	$ 17

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Consolidated Statements of Stockholders Equity - USD ($) shares in Thousands, $ in Millions	Total	Common Stock [Member]	Additional Paid In Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]
BALANCE at Dec. 31, 2017	$ 8,915	$ 0	$ 7,142	$ 1,840	$ (67)
BALANCE, Shares at Dec. 31, 2017		149,325			598
Net income (loss)	835	$ 0	0	835	$ 0
Grants of restricted stock, shares		112
Performance unit share conversion, shares		446
Cancellation of restricted stock, shares		(13)
Stock-based compensation	17		17
Purchase of treasury stock	(29)				$ (29)
Purchase of treasury stock, shares					202
BALANCE, Shares at Mar. 31, 2018		149,870			800
BALANCE at Mar. 31, 2018	9,738	$ 0	7,159	2,675	$ (96)
BALANCE at Dec. 31, 2018	18,768	$ 0	14,773	4,126	$ (131)
BALANCE, Shares at Dec. 31, 2018		201,289			1,032
Net income (loss)	(695)	$ 0	0	(695)	$ 0
Common stock dividends ($0.125 per share)	(25)			(25)
Grants of restricted stock, shares		235
Performance unit share conversion, shares		246
Cancellation of restricted stock, shares		(15)
Stock-based compensation	24	$ 0	24	0	0
Purchase of treasury stock	(13)	$ 0	0	0	$ (13)
Purchase of treasury stock, shares					124
BALANCE, Shares at Mar. 31, 2019		201,755			1,156
BALANCE at Mar. 31, 2019	$ 18,059	$ 0	$ 14,797	$ 3,406	$ (144)

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Consolidated Statements of Stockholders Equity (Parenthetical)	Mar. 31, 2019 $ / shares
Statement of Stockholders' Equity [Abstract]
Dividends declared, amount per share	$ 0.125

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (695)	$ 835
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	465	317
Accretion of discount on asset retirement obligations	3	2
Exploration and abandonments	38	10
Non-cash stock-based compensation expense	24	17
Deferred income taxes	(194)	254
Gain on disposition of assets, net	(1)	(723)
Loss on derivatives	1,059	35
Net settlements on derivatives	0	(112)
Other	2	(96)
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable	(111)	(81)
Prepaid costs and other	9	(2)
Inventory	0	3
Accounts payable	11	(12)
Revenue payable	8	2
Other current liabilities	5	39
Net cash provided by operating activities	623	488
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and natural gas properties	(885)	(474)
Acquisitions of oil and natural gas properties	(5)	(13)
Additions to property, equipment and other assets	(15)	(6)
Proceeds from the disposition of assets	5	255
Direct transaction costs for disposition of assets	(2)	(3)
Distribution from equity method investment	0	148
Net cash used in investing activities	(902)	(93)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	1,112	662
Payments on credit facility	(739)	(984)
Payment of common stock dividends	(25)	0
Purchase of treasury stock	(13)	(29)
Decrease in bank overdrafts	(54)	(44)
Other	(2)	0
Net cash provided by (used in) financing activities	279	(395)
Net increase in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	$ 0	$ 0

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Organization and nature of operations

3 Months Ended

Mar. 31, 2019

Organization and nature of operations [Abstract]

Organization and nature of operations

Note 1. Organization and nature of operations

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

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Basis of presentation and summary of significant accounting policies

3 Months Ended

Mar. 31, 2019

Basis of presentation and summary of significant accounting policies [Abstract]

Basis of presentation and summary of significant accounting policies

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.

At March 31,2019, the Company owned a 23.75 percent membership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering and transportation system in the Delaware Basin. 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 remaining distribution of approximately $103 million was recorded in other income (expense) on the Company’s consolidated statement of operations since the lenders to the term loan do not have recourse against the Company, and the Company has no contractual obligation to repay the distribution.

The Company’s net investment in Oryx was zero at March 31,2019 and December 31, 2018. The Company did not record income or loss on the Oryx investment for the three months ended March 31, 2019, as cumulative net income had yet to exceed the distribution in excess of the Company’s investment. In April 2019, Oryx entered into an agreement to sell 100 percent of its equity interests, which includedthe Company’s 23.75 percent membership interest.

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 March 31,2019 and December 31, 2018, the Company had receivables related to contracts with customers of approximately $530 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 as they represent payment for services performed outside of the contract with the customer.

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 costs, 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 reductionsto general and administrative expense. Such fees totaled approximately $4 million for each of the three months ended March 31,2019 and 2018.

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 does not currently 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 approximately $19 million and $16 million relate to the Company’s operating and finance leases, respectively, and approximately $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. The 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 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 is currently assessing the effect that ASU 2018-18 will have on its financial position, results of operations and disclosures.

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RSP acquisition

3 Months Ended

Mar. 31, 2019

RSP Acquisition [Abstract]

RSP Acquisition

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’spreliminary 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			124
	Long-term debt			1,758
	Deferred income taxes			514
	Asset retirement obligations			20
	Noncurrent derivative instruments			5
		Total liabilities assumed	$	2,558
		Total purchase price plus liabilities assumed	$	10,107
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			2,229
		Total assets acquired	$	10,107

Pro forma data.The following unaudited pro forma combined condensed financial data for the three months ended March 31, 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.

		Three Months Ended
(in millions, except per share amounts)		March 31, 2018
Operating revenues		$	1,226
Net income		$	931
Earnings per share:
	Basic net income	$	4.66
	Diluted net income	$	4.64

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Other acquisitions, divestitures and nonmonetary transactions

3 Months Ended

Mar. 31, 2019

Acquisitions, Divestitures, And Non-Monetary Transactions [Abstract]

Acquisitions, divestitures and nonmonetary transactions

Note 4. Other acquisitions, divestitures and nonmonetary transactions

During the three months ended March 31,2018, 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 three months ended March 31, 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 three months ended March 31,2018. The assets divested included proved and unproved oil and natural gas properties on approximately 20,000 net acres.

Nonmonetary transactions. During the three months ended March 31,2018, 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 $14 million, included in gain on disposition of assets, net on the Company’s consolidated statement of operations for the three months ended March 31, 2018.

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Stock incentive plan

3 Months Ended

Mar. 31, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock incentive plan

Note 5.Stock incentive plan

The Company’s 2015 Stock Incentive Plan (“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. At the end of each performance period, each performance unit award will convertinto 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. The total number of units converted to restricted stock awards will depend on the Company’s performance at the end of each performance period. All other performance unit awards have 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 thePlan for the three months ended March 31,2019 is presented below:

		Restricted			Performance
		Stock Shares			Units
Outstanding at December 31, 2018			1,364,699		218,391
	Awards granted (a)		235,082		212,947	(b)
	Awards cancelled / forfeited		(14,947)		-
	Lapse of restrictions		(146,048)		-
Outstanding at March 31, 2019		1,438,786		431,338
(a)	Weighted average grant date fair value per share/unit	$	105.52	$	144.03
(b)	Includes 38,952 performance award units 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 March 31,2019:

(in millions)
Remaining 2019		$	61
2020			48
2021			22
2022			4
2023			2
2024			1
Thereafter			2
	Total	$	140

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Disclosures about fair value measurements

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Disclosures about fair value measurements

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.

Financial Assets and Liabilities Measured at Fair Value

The following table presents the carrying amounts and fair values of the Company’s financial instruments at March 31,2019 and December 31, 2018:

			March 31, 2019				December 31, 2018
			Carrying		Fair		Carrying		Fair
(in millions)			Value		Value		Value		Value
Assets:
		Derivative instruments	$	3	$	3	$	695	$	695
Liabilities:
		Derivative instruments	$	367	$	367	$	-	$	-
		Credit facility	$	615	$	615	$	242	$	242
		$600 million 4.375% senior notes due 2025 (a)	$	594	$	617	$	594	$	591
		$1,000 million 3.75% senior notes due 2027 (a)	$	989	$	991	$	989	$	939
		$1,000 million 4.3% senior notes due 2028 (a)	$	988	$	1,033	$	988	$	980
		$800 million 4.875% senior notes due 2047 (a)	$	789	$	849	$	789	$	761
		$600 million 4.85% senior notes due 2048 (a)	$	592	$	634	$	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.

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 March 31,2019 and December 31, 2018. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.

March 31, 2019
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable		Total		Consolidated		Consolidated
				Assets				Inputs		Inputs		Fair		Balance		Balance
(in millions)				(Level 1)				(Level 2)		(Level 3)		Value		Sheet		Sheet
	Assets:
		Current:
			Commodity derivatives		$	-	$	57	$	-	$	57	$	(56)	$	1
		Noncurrent:
			Commodity derivatives			-		29		-		29		(27)		2
	Liabilities:
		Current:
			Commodity derivatives			-		(348)		-		(348)		56		(292)
		Noncurrent:
			Commodity derivatives			-		(102)		-		(102)		27		(75)
	Net derivative instruments				$	-	$	(364)	$	-	$	(364)	$	-	$	(364)

December 31, 2018
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable		Total		Consolidated		Consolidated
				Assets				Inputs		Inputs		Fair		Balance		Balance
(in millions)				(Level 1)				(Level 2)		(Level 3)		Value		Sheet		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 March 31,2019, 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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Derivative financial instruments

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative financial instruments

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 thethreemonths ended March 31,2019 and 2018:

			Three Months Ended
			March 31,
(in millions)				2019		2018
Loss on derivatives:
	Oil derivatives		$	(1,056)	$	(33)
	Natural gas derivatives			(3)		(2)
		Total	$	(1,059)	$	(35)
The following table represents the Company’s net cash receipts from (payments on) derivatives for the three months ended March 31, 2019 and 2018:
			Three Months Ended
			March 31,
(in millions)				2019		2018
Net cash receipts from (payments on) derivatives:
	Oil derivatives		$	3	$	(113)
	Natural gas derivatives			(3)		1
		Total	$	-	$	(112)

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

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Price Swaps: (a)
	2019:
		Volume (Bbl)		-		15,112,750		13,378,000		11,232,000		39,722,750
		Price per Bbl	$	-	$	56.59	$	56.41	$	55.88	$	56.33
	2020:
		Volume (Bbl)		10,502,500		10,166,500		9,453,000		9,218,000		39,340,000
		Price per Bbl	$	57.28	$	57.24	$	57.18	$	57.14	$	57.21
	2021:
		Volume (Bbl)		2,160,000		2,184,000		2,024,000		2,024,000		8,392,000
		Price per Bbl	$	54.57	$	54.57	$	54.50	$	54.50	$	54.54
Oil Costless Collars: (a)
	2019:
		Volume (Bbl)		-		1,213,250		1,135,000		1,058,000		3,406,250
		Ceiling price per Bbl	$	-	$	64.00	$	63.47	$	62.95	$	63.50
		Floor price per Bbl	$	-	$	56.06	$	55.74	$	55.43	$	55.76
Oil Basis Swaps: (b)
	2019:
		Volume (Bbl)		-		11,965,500		12,650,000		15,133,000		39,748,500
		Price per Bbl	$	-	$	(3.03)	$	(2.82)	$	(2.32)	$	(2.69)
	2020:
		Volume (Bbl)		13,013,000		10,192,000		10,120,000		10,120,000		43,445,000
		Price per Bbl	$	(0.53)	$	(0.70)	$	(0.71)	$	(0.71)	$	(0.65)
	2021:
		Volume (Bbl)		2,070,000		2,093,000		2,116,000		2,116,000		8,395,000
		Price per Bbl	$	0.55	$	0.55	$	0.55	$	0.55	$	0.55
Natural Gas Price Swaps: (c)
	2019:
		Volume (MMBtu)		-		17,241,387		17,298,537		17,209,535		51,749,459
		Price per MMBtu	$	-	$	2.87	$	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 ofcounterparties 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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Debt

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Debt

Note 8. Debt

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

				March 31,		December 31,
(in millions)				2019		2018
Credit facility due 2022			$	615	$	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				(38)		(38)
	Less: current portion			-		-
		Total long-term debt	$	4,567	$	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 March 31,2019, the Company’s commitments from its bank group were $2.0 billion, of which $1.4 billion was unused commitments, net of letters of credit. During the three months ended March 31,2019, the weighted average interest rate on the Credit Facility was 4.4 percent.At March 31,2019, 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 March 31,2019, 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 thethreemonths ended March 31,2019 and 2018:

		Three Months Ended
		March 31,
(in millions)			2019		2018
Cash payments for interest		$	63	$	18
Non-cash interest			1		1
Net changes in accruals			(13)		12
	Interest costs incurred		51		31
Less: capitalized interest			(4)		(1)
	Total interest expense	$	47	$	30

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Commitments and contingencies

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and contingencies

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 believesthat 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 March 31,2019:

(in millions)
Remaining 2019		$	35
2020			75
2021			76
2022			36
2023			33
2024			34
Thereafter			96
	Total	$	385

At March 31, 2019, the Company’s delivery commitments covered the following gross volumes of oil and natural gas:

		Oil	Natural Gas
		(MMBbl)	(MMcf)
Remaining 2019		12	2,697
2020		36	10,286
2021		39	21,627
2022		41	16,425
2023		33	16,425
2024		33	16,470
Thereafter		114	32,850
	Total	308	116,780

Other commitments.In May 2018, the Company entered into a one-year term oil marketing contract with a third-party purchaser. The contract requires the Company to deliver not less than seven thousand barrels per day. Should there be a delivery shortfall in any given month, the Company retains an option to deliver the shortfall volume in any two subsequent months; however, failure to meet this volume delivery commitment would result in a penalty equal to the volume shortfall multiplied by the then market price for oil.If production is not sufficient to meet the sales commitment, the Company may purchase commodities in the market to satisfy its commitment.

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 startup of Cactus II Pipeline system 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. 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 March 31, 2019:

(in millions)		Classification	March 31, 2019
Assets
Operating lease right-of-use assets		Other property and equipment, net	$	18
Finance lease right-of-use assets		Other property and equipment, net		15
Total lease right-of-use assets (a)			$	33
Liabilities
Current:
Operating		Other current liabilities	$	7
Finance		Other current liabilities		6
Noncurrent:
Operating		Asset retirement obligations and other long-term liabilities		13
Finance		Asset retirement obligations and other long-term liabilities		10
Total lease liabilities (a)			$	36
(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.

The following table provides the components of lease cost, excluding lease cost related to short-term leases, for the three months ended March 31,2019:

			Three Months Ended
(in millions)		Classification	March 31, 2019
Operating lease cost		General and administrative	$	2
Finance lease cost		Depreciation, depletion, and amortization (a)		2
Total lease cost			$	4
(a)	Interest on lease liabilities related to finance leases was immaterial during the three months ended March 31, 2019.

The Company’s short-term leases are comprised primarily of drilling rigs and certain field equipment. During the three months ended March 31, 2019, the Company’s gross lease cost related to its short-term leases was $94 million, of which $67 million was 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 three months ended March 31,2019:

		Three Months Ended
(in millions)		March 31, 2019
Cash paid for amounts included in measurement of lease liabilities:
Operating cash flows from operating leases	$	2
Financing cash flows from finance leases	$	2
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	-
Finance leases	$	3

The following table provides lease terms and discount rates related to leases at March 31,2019:

	March 31, 2019
Weighted average remaining lease term (years):
Operating leases		3.5
Finance leases		2.9
Weighted average discount rate:
Operating leases		4.9%
Finance leases		4.4%

The following table provides maturities of lease liabilities at March 31,2019:

(in millions)		Operating Leases		Finance Leases
Remaining 2019	$	6	$	5
2020		8		6
2021		6		4
2022		1		2
Thereafter		1		-
Total lease payments		22		17
Less: interest		(2)		(1)
Present value of lease liabilities	$	20	$	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 for the three months ended March 31, 2018.

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

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Income taxes

3 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

Income taxes

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 March 31,2019 and 2018, the Company recorded an income tax benefit of approximately $194 million and anincome tax expense of approximately $254 million, respectively. The change is primarily due to the pre-tax loss for the three months ended March 31,2019 as compared to thepre-tax income for the three months ended March 31,2018.

The effective income tax rates were 22 percent and 23 percent for the three months ended March 31,2019 and 2018, respectively.

The difference between the Company’s effective tax rates for the three months ended March 31,2019 as compared to 2018 is primarily due to the research and development credit, net of unrecognized tax benefits, partially offset by the impact of other items. The Company recorded a discrete income tax benefit related to stock-based awards of approximately $2 million for each of the three months ended March 31,2019 and 2018.

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 March 31,2019, 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

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Related party transactions

3 Months Ended

Mar. 31, 2019

Related Party Transactions [Abstract]

Related party transactions

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 partnership interest.

At March 31,2019, the Company had an ownership interest in an entity that operates and manages various water infrastructure assets located in the Permian Basin and accounts for this investment using the equity method. The Company also has a water management services agreement with this entity under which the Company pays a fee for each barrel of produced water.

The payments to the Company’s related parties totaled approximately $6 million and $1 million for the three months ended March 31,2019 and 2018, respectively.

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Earnings per share

3 Months Ended

Mar. 31, 2019

Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]

Earnings per share

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 threemonths ended March 31,2019 and 2018, respectively, under the two-class method:

			Three Months Ended
			March 31,
(in millions)			2019		2018
Net income (loss) as reported			$	(695)	$	835
Participating basic earnings (a)				-		(6)
	Basic earnings (loss) attributable to common stockholders			(695)		829
Reallocation of participating earnings				-		-
	Diluted earnings (loss) attributable to common stockholders		$	(695)	$	829
(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 thethreemonths ended March 31,2019 and 2018:

			Three Months Ended
			March 31,
(in thousands)			2019	2018
Weighted average common shares outstanding:
	Basic		199,148	147,925
		Dilutive performance units	-	537
	Diluted		199,148	148,462

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
		March 31,
(in thousands)		2019	2018
Number of antidilutive units:
	Performance units	324	-

Performance unit awards. The number of shares of common stock that will ultimately be issued for performance units will be determined by a combination of (i) comparing the Company’s total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. The performance period 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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Subsidiary guarantors

3 Months Ended

Mar. 31, 2019

Guarantees [Abstract]

Subsidiary guarantors

Note 13. Subsidiary guarantors

At March 31,2019, 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 8for 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 March 31,2019 and December 31, 2018, condensed consolidating statements of operations for thethree months ended March 31,2019 and 2018and condensed consolidating statements of cash flows for thethree months ended March 31,2019 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.

Condensed Consolidating Balance Sheet
March 31, 2019
			Parent	Subsidiary			Subsidiary		Consolidating
(in millions)			Issuer	Guarantors		Non-Guarantor			Entries		Total
ASSETS
Accounts receivable - related parties		$	18,518	$	-	$	-	$	(18,518)	$	-
Other current assets			6		1,021		-		-		1,027
Oil and natural gas properties, net			-		22,405		16		-		22,421
Property and equipment, net			-		350		-		-		350
Investment in subsidiaries			5,629		-		-		(5,629)		-
Goodwill			-		2,229		-		-		2,229
Other long-term assets			15		126		-		-		141
	Total assets	$	24,168	$	26,131	$	16	$	(24,147)	$	26,168
LIABILITIES AND EQUITY
Accounts payable - related parties		$	-	$	18,502	$	16	$	(18,518)	$	-
Other current liabilities			368		1,292		-		-		1,660
Long-term debt			4,567		-		-		-		4,567
Other long-term liabilities			1,174		708		-		-		1,882
Equity			18,059		5,629		-		(5,629)		18,059
	Total liabilities and equity	$	24,168	$	26,131	$	16	$	(24,147)	$	26,168

Condensed Consolidating Balance Sheet
December 31, 2018
			Parent	Subsidiary			Subsidiary	Consolidating
(in millions)			Issuer	Guarantors		Non-Guarantor			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

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2019
			Parent		Subsidiary		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Non-Guarantor		Entries		Total
Total operating revenues		$	-	$	1,104	$	-	$	-	$	1,104
Total operating costs and expenses			(1,060)		(890)		-		-		(1,950)
	Income (loss) from operations		(1,060)		214		-		-		(846)
Interest expense			(47)		-		-		-		(47)
Other, net			218		4		-		(218)		4
	Income (loss) before income taxes		(889)		218		-		(218)		(889)
Income tax benefit			194		-		-		-		194
	Net income (loss)	$	(695)	$	218	$	-	$	(218)	$	(695)

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2018
			Parent		Subsidiary		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Non-Guarantors		Entries		Total
Total operating revenues		$	-	$	942	$	5	$	-	$	947
Total operating costs and expenses			(34)		105		(3)		-		68
	Income (loss) from operations		(34)		1,047		2		-		1,015
Interest expense			(30)		-		-		-		(30)
Other, net			1,153		104		-		(1,153)		104
	Income before income taxes		1,089		1,151		2		(1,153)		1,089
Income tax expense			(254)		-		-		-		(254)
	Net income	$	835	$	1,151	$	2	$	(1,153)	$	835

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2019
		Parent		Subsidiary		Subsidiary			Consolidating
(in millions)		Issuer		Guarantors		Non-Guarantor			Entries			Total
Net cash flows provided by (used in) operating activities		$	(335)	$	958		$	-	$	-	$	623
Net cash flows used in investing activities			-		(902)			-		-		(902)
Net cash flows provided by (used in) financing activities			335		(56)			-		-		279
	Net increase 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
Three Months Ended March 31, 2018
		Parent		Subsidiary		Subsidiary			Consolidating
(in millions)		Issuer		Guarantors		Non-Guarantor			Entries			Total
Net cash flows provided by operating activities		$	351	$	137		$	-	$	-	$	488
Net cash flows used in investing activities			-		(93)			-		-		(93)
Net cash flows used in financing activities			(351)		(44)			-		-		(395)
	Net increase in cash and cash equivalents		-		-			-		-		-
	Cash and cash equivalents at beginning of period		-		-			-		-		-
	Cash and cash equivalents at end of period	$	-	$	-		$	-	$	-	$	-

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Subsequent events

3 Months Ended

Mar. 31, 2019

Subsequent Events [Abstract]

Subsequent events

Note 14. Subsequent events

Oryx divestiture.In April 2019, Oryx entered into an agreement to sell 100 percent of its equity interests. The Company expects to receive approximately $300 million, net of closing costs, for its 23.75 percent membership interest.

Midstream joint venture.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.

2019 dividends. On April 30, 2019, the Company’s board of directors approved a cash dividend of $0.125 per share for the second quarter of 2019 that is expected to be paid on June 28, 2019 to stockholders of record as of May 10, 2019.

New commodity derivative contracts.After March 31,2019, the Company entered into the following derivative contractsto hedge additional amounts of estimated future production

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Price Swaps: (a)
	2019:
		Volume (Bbl)		-		1,707,000		1,451,000		1,281,000		4,439,000
		Price per Bbl	$	-	$	62.64	$	63.14	$	63.43	$	63.03
	2021:
		Volume (Bbl)		1,170,000		1,183,000		1,196,000		1,196,000		4,745,000
		Price per Bbl	$	56.72	$	56.72	$	56.72	$	56.72	$	56.72
Oil Basis Swaps: (b)
	2019:
		Volume (Bbl)		-		-		92,000		920,000		1,012,000
		Price per Bbl	$	-	$	-	$	(1.05)	$	(0.07)	$	(0.16)
	2020:
		Volume (Bbl)		1,092,000		-		-		-		1,092,000
		Price per Bbl	$	0.10	$	-	$	-	$	-	$	0.10
	2021:
		Volume (Bbl)		540,000		546,000		552,000		552,000		2,190,000
		Price per Bbl	$	0.50	$	0.50	$	0.50	$	0.50	$	0.50
(a)	The oil derivative contracts are settled based on the NYMEX – WTI calendar-month average futures price.
(b)	The basis differential price is between Midland – WTI and Cushing – WTI. These contracts are settled on a calendar-month basis.

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Supplementary Information

3 Months Ended

Mar. 31, 2019

Supplementary Information [Abstract]

Supplementary information

Note 15. Supplementary information

Capitalized costs

			March 31,		December 31,
(in millions)			2019		2018
Oil and natural gas properties:
	Proved		$	26,000	$	24,992
	Unproved			6,559		6,714
	Less: accumulated depletion			(10,138)		(9,701)
		Net capitalized costs for oil and natural gas properties	$	22,421	$	22,005

Costs incurred for oil and natural gas producing activities

		Three Months Ended
		March 31,
(in millions)		2019		2018
Property acquisition costs:
	Proved	$	-	$	-
	Unproved		4		13
Exploration			462		243
Development			464		207
	Total costs incurred for oil and natural gas properties	$	930	$	463

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Basis of presentation and summary of significant accounting policies (Policies)

3 Months Ended

Mar. 31, 2019

Basis of presentation and summary of significant accounting policies [Abstract]

Principles of consolidation

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

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

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

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

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.

At March 31,2019, the Company owned a 23.75 percent membership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering and transportation system in the Delaware Basin. 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 remaining distribution of approximately $103 million was recorded in other income (expense) on the Company’s consolidated statement of operations since the lenders to the term loan do not have recourse against the Company, and the Company has no contractual obligation to repay the distribution.

The Company’s net investment in Oryx was zero at March 31,2019 and December 31, 2018. The Company did not record income or loss on the Oryx investment for the three months ended March 31, 2019, as cumulative net income had yet to exceed the distribution in excess of the Company’s investment. In April 2019, Oryx entered into an agreement to sell 100 percent of its equity interests, which includedthe Company’s 23.75 percent membership interest.

Litigation contingencies

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

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 March 31,2019 and December 31, 2018, the Company had receivables related to contracts with customers of approximately $530 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 as they represent payment for services performed outside of the contract with the customer.

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 costs, 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

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 reductionsto general and administrative expense. Such fees totaled approximately $4 million for each of the three months ended March 31,2019 and 2018.

Recently adopted accounting pronouncements and new accounting pronouncements issued but not yet adopted

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 does not currently 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 approximately $19 million and $16 million relate to the Company’s operating and finance leases, respectively, and approximately $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. The 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 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 is currently assessing the effect that ASU 2018-18 will have on its financial position, results of operations and disclosures.

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RSP acquisition (Tables)

3 Months Ended

Mar. 31, 2019

Business Acquisition [Line Items]

Purchase Price Allocation

The following table sets forth the Company’spreliminary 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			124
	Long-term debt			1,758
	Deferred income taxes			514
	Asset retirement obligations			20
	Noncurrent derivative instruments			5
		Total liabilities assumed	$	2,558
		Total purchase price plus liabilities assumed	$	10,107
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			2,229
		Total assets acquired	$	10,107

Schedule of Pro Forma Information

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.

		Three Months Ended
(in millions, except per share amounts)		March 31, 2018
Operating revenues		$	1,226
Net income		$	931
Earnings per share:
	Basic net income	$	4.66
	Diluted net income	$	4.64

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Stock incentive plan (Tables)

3 Months Ended

Mar. 31, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of restricted stock shares and preformance unit activity

A summary of the Company’s restricted stock shares and performance unit activity under thePlan for the three months ended March 31,2019 is presented below:

		Restricted			Performance
		Stock Shares			Units
Outstanding at December 31, 2018			1,364,699		218,391
	Awards granted (a)		235,082		212,947	(b)
	Awards cancelled / forfeited		(14,947)		-
	Lapse of restrictions		(146,048)		-
Outstanding at March 31, 2019		1,438,786		431,338
(a)	Weighted average grant date fair value per share/unit	$	105.52	$	144.03
(b)	Includes 38,952 performance award units 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.

Future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding

The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at March 31,2019:

(in millions)
Remaining 2019		$	61
2020			48
2021			22
2022			4
2023			2
2024			1
Thereafter			2
	Total	$	140

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Disclosures about fair value measurements (Tables)

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Carrying amounts and fair values of the Company's financial instruments

The following table presents the carrying amounts and fair values of the Company’s financial instruments at March 31,2019 and December 31, 2018:

			March 31, 2019				December 31, 2018
			Carrying		Fair		Carrying		Fair
(in millions)			Value		Value		Value		Value
Assets:
		Derivative instruments	$	3	$	3	$	695	$	695
Liabilities:
		Derivative instruments	$	367	$	367	$	-	$	-
		Credit facility	$	615	$	615	$	242	$	242
		$600 million 4.375% senior notes due 2025 (a)	$	594	$	617	$	594	$	591
		$1,000 million 3.75% senior notes due 2027 (a)	$	989	$	991	$	989	$	939
		$1,000 million 4.3% senior notes due 2028 (a)	$	988	$	1,033	$	988	$	980
		$800 million 4.875% senior notes due 2047 (a)	$	789	$	849	$	789	$	761
		$600 million 4.85% senior notes due 2048 (a)	$	592	$	634	$	592	$	573
(a)	The carrying value includes associated deferred loan costs and any discount.

Net basis derivative fair values as reported in the consolidated balance sheets

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 March 31,2019 and December 31, 2018. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.

March 31, 2019
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable		Total		Consolidated		Consolidated
				Assets				Inputs		Inputs		Fair		Balance		Balance
(in millions)				(Level 1)				(Level 2)		(Level 3)		Value		Sheet		Sheet
	Assets:
		Current:
			Commodity derivatives		$	-	$	57	$	-	$	57	$	(56)	$	1
		Noncurrent:
			Commodity derivatives			-		29		-		29		(27)		2
	Liabilities:
		Current:
			Commodity derivatives			-		(348)		-		(348)		56		(292)
		Noncurrent:
			Commodity derivatives			-		(102)		-		(102)		27		(75)
	Net derivative instruments				$	-	$	(364)	$	-	$	(364)	$	-	$	(364)

December 31, 2018
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable		Total		Consolidated		Consolidated
				Assets				Inputs		Inputs		Fair		Balance		Balance
(in millions)				(Level 1)				(Level 2)		(Level 3)		Value		Sheet		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

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Derivative financial instruments (Tables)

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of the gains and losses reported in earnings related to the commodity derivative instruments

The following table summarizes the amounts reported in earnings related to the commodity derivative instruments for thethreemonths ended March 31,2019 and 2018:

			Three Months Ended
			March 31,
(in millions)				2019		2018
Loss on derivatives:
	Oil derivatives		$	(1,056)	$	(33)
	Natural gas derivatives			(3)		(2)
		Total	$	(1,059)	$	(35)
The following table represents the Company’s net cash receipts from (payments on) derivatives for the three months ended March 31, 2019 and 2018:
			Three Months Ended
			March 31,
(in millions)				2019		2018
Net cash receipts from (payments on) derivatives:
	Oil derivatives		$	3	$	(113)
	Natural gas derivatives			(3)		1
		Total	$	-	$	(112)

Company's outstanding derivative contracts

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

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Price Swaps: (a)
	2019:
		Volume (Bbl)		-		15,112,750		13,378,000		11,232,000		39,722,750
		Price per Bbl	$	-	$	56.59	$	56.41	$	55.88	$	56.33
	2020:
		Volume (Bbl)		10,502,500		10,166,500		9,453,000		9,218,000		39,340,000
		Price per Bbl	$	57.28	$	57.24	$	57.18	$	57.14	$	57.21
	2021:
		Volume (Bbl)		2,160,000		2,184,000		2,024,000		2,024,000		8,392,000
		Price per Bbl	$	54.57	$	54.57	$	54.50	$	54.50	$	54.54
Oil Costless Collars: (a)
	2019:
		Volume (Bbl)		-		1,213,250		1,135,000		1,058,000		3,406,250
		Ceiling price per Bbl	$	-	$	64.00	$	63.47	$	62.95	$	63.50
		Floor price per Bbl	$	-	$	56.06	$	55.74	$	55.43	$	55.76
Oil Basis Swaps: (b)
	2019:
		Volume (Bbl)		-		11,965,500		12,650,000		15,133,000		39,748,500
		Price per Bbl	$	-	$	(3.03)	$	(2.82)	$	(2.32)	$	(2.69)
	2020:
		Volume (Bbl)		13,013,000		10,192,000		10,120,000		10,120,000		43,445,000
		Price per Bbl	$	(0.53)	$	(0.70)	$	(0.71)	$	(0.71)	$	(0.65)
	2021:
		Volume (Bbl)		2,070,000		2,093,000		2,116,000		2,116,000		8,395,000
		Price per Bbl	$	0.55	$	0.55	$	0.55	$	0.55	$	0.55
Natural Gas Price Swaps: (c)
	2019:
		Volume (MMBtu)		-		17,241,387		17,298,537		17,209,535		51,749,459
		Price per MMBtu	$	-	$	2.87	$	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.

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Debt (Tables)

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Company's debt

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

				March 31,		December 31,
(in millions)				2019		2018
Credit facility due 2022			$	615	$	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				(38)		(38)
	Less: current portion			-		-
		Total long-term debt	$	4,567	$	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.

Interest expense

The following amounts have been incurred and charged to interest expense for thethreemonths ended March 31,2019 and 2018:

		Three Months Ended
		March 31,
(in millions)			2019		2018
Cash payments for interest		$	63	$	18
Non-cash interest			1		1
Net changes in accruals			(13)		12
	Interest costs incurred		51		31
Less: capitalized interest			(4)		(1)
	Total interest expense	$	47	$	30

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Commitments and contingencies (Tables)

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Summary of the Company's future commitments

The following table summarizes the Company’s commitments at March 31,2019:

(in millions)
Remaining 2019		$	35
2020			75
2021			76
2022			36
2023			33
2024			34
Thereafter			96
	Total	$	385

Oil and natural gas delivery commitments

At March 31, 2019, the Company’s delivery commitments covered the following gross volumes of oil and natural gas:

		Oil	Natural Gas
		(MMBbl)	(MMcf)
Remaining 2019		12	2,697
2020		36	10,286
2021		39	21,627
2022		41	16,425
2023		33	16,425
2024		33	16,470
Thereafter		114	32,850
	Total	308	116,780

Supplemental balance sheet information related to leases

The following table provides supplemental consolidated balance sheet information related to leases at March 31, 2019:

(in millions)		Classification	March 31, 2019
Assets
Operating lease right-of-use assets		Other property and equipment, net	$	18
Finance lease right-of-use assets		Other property and equipment, net		15
Total lease right-of-use assets (a)			$	33
Liabilities
Current:
Operating		Other current liabilities	$	7
Finance		Other current liabilities		6
Noncurrent:
Operating		Asset retirement obligations and other long-term liabilities		13
Finance		Asset retirement obligations and other long-term liabilities		10
Total lease liabilities (a)			$	36
(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.

Components of lease expense

The following table provides the components of lease cost, excluding lease cost related to short-term leases, for the three months ended March 31,2019:

			Three Months Ended
(in millions)		Classification	March 31, 2019
Operating lease cost		General and administrative	$	2
Finance lease cost		Depreciation, depletion, and amortization (a)		2
Total lease cost			$	4
(a)	Interest on lease liabilities related to finance leases was immaterial during the three months ended March 31, 2019.

Supplemental cash flow information related to leases

The following table summarizes supplemental cash flow information related to leases for the three months ended March 31,2019:

		Three Months Ended
(in millions)		March 31, 2019
Cash paid for amounts included in measurement of lease liabilities:
Operating cash flows from operating leases	$	2
Financing cash flows from finance leases	$	2
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	-
Finance leases	$	3

Lease terms and discount rates related to leases

The following table provides lease terms and discount rates related to leases at March 31,2019:

	March 31, 2019
Weighted average remaining lease term (years):
Operating leases		3.5
Finance leases		2.9
Weighted average discount rate:
Operating leases		4.9%
Finance leases		4.4%

Maturity and present value of lease liabilities

The following table provides maturities of lease liabilities at March 31,2019:

(in millions)		Operating Leases		Finance Leases
Remaining 2019	$	6	$	5
2020		8		6
2021		6		4
2022		1		2
Thereafter		1		-
Total lease payments		22		17
Less: interest		(2)		(1)
Present value of lease liabilities	$	20	$	16

Future minimum lease commitments under non-cancellable operating leases

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

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Earnings per share (Tables)

3 Months Ended

Mar. 31, 2019

Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]

Reconciliation of earnings attributable to common shares, basic and diluted

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 threemonths ended March 31,2019 and 2018, respectively, under the two-class method:

			Three Months Ended
			March 31,
(in millions)			2019		2018
Net income (loss) as reported			$	(695)	$	835
Participating basic earnings (a)				-		(6)
	Basic earnings (loss) attributable to common stockholders			(695)		829
Reallocation of participating earnings				-		-
	Diluted earnings (loss) attributable to common stockholders		$	(695)	$	829
(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.

Reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for thethreemonths ended March 31,2019 and 2018:

			Three Months Ended
			March 31,
(in thousands)			2019	2018
Weighted average common shares outstanding:
	Basic		199,148	147,925
		Dilutive performance units	-	537
	Diluted		199,148	148,462

Summary of the performance units that were not included in the computation of diluted net income per share

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
		March 31,
(in thousands)		2019	2018
Number of antidilutive units:
	Performance units	324	-

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Subsidiary guarantors (Tables)

3 Months Ended

Mar. 31, 2019

Guarantees [Abstract]

Condensed Consolidating Balance Sheet

The following condensed consolidating balance sheets at March 31,2019 and December 31, 2018, condensed consolidating statements of operations for thethree months ended March 31,2019 and 2018and condensed consolidating statements of cash flows for thethree months ended March 31,2019 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.

Condensed Consolidating Balance Sheet
March 31, 2019
			Parent	Subsidiary			Subsidiary		Consolidating
(in millions)			Issuer	Guarantors		Non-Guarantor			Entries		Total
ASSETS
Accounts receivable - related parties		$	18,518	$	-	$	-	$	(18,518)	$	-
Other current assets			6		1,021		-		-		1,027
Oil and natural gas properties, net			-		22,405		16		-		22,421
Property and equipment, net			-		350		-		-		350
Investment in subsidiaries			5,629		-		-		(5,629)		-
Goodwill			-		2,229		-		-		2,229
Other long-term assets			15		126		-		-		141
	Total assets	$	24,168	$	26,131	$	16	$	(24,147)	$	26,168
LIABILITIES AND EQUITY
Accounts payable - related parties		$	-	$	18,502	$	16	$	(18,518)	$	-
Other current liabilities			368		1,292		-		-		1,660
Long-term debt			4,567		-		-		-		4,567
Other long-term liabilities			1,174		708		-		-		1,882
Equity			18,059		5,629		-		(5,629)		18,059
	Total liabilities and equity	$	24,168	$	26,131	$	16	$	(24,147)	$	26,168

Condensed Consolidating Balance Sheet
December 31, 2018
			Parent	Subsidiary			Subsidiary	Consolidating
(in millions)			Issuer	Guarantors		Non-Guarantor			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

Condensed Consolidating Statement of Operations

The following condensed consolidating balance sheets at March 31,2019 and December 31, 2018, condensed consolidating statements of operations for thethree months ended March 31,2019 and 2018and condensed consolidating statements of cash flows for thethree months ended March 31,2019 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.

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2019
			Parent		Subsidiary		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Non-Guarantor		Entries		Total
Total operating revenues		$	-	$	1,104	$	-	$	-	$	1,104
Total operating costs and expenses			(1,060)		(890)		-		-		(1,950)
	Income (loss) from operations		(1,060)		214		-		-		(846)
Interest expense			(47)		-		-		-		(47)
Other, net			218		4		-		(218)		4
	Income (loss) before income taxes		(889)		218		-		(218)		(889)
Income tax benefit			194		-		-		-		194
	Net income (loss)	$	(695)	$	218	$	-	$	(218)	$	(695)

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2018
			Parent		Subsidiary		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Non-Guarantors		Entries		Total
Total operating revenues		$	-	$	942	$	5	$	-	$	947
Total operating costs and expenses			(34)		105		(3)		-		68
	Income (loss) from operations		(34)		1,047		2		-		1,015
Interest expense			(30)		-		-		-		(30)
Other, net			1,153		104		-		(1,153)		104
	Income before income taxes		1,089		1,151		2		(1,153)		1,089
Income tax expense			(254)		-		-		-		(254)
	Net income	$	835	$	1,151	$	2	$	(1,153)	$	835

Condensed Consolidating Statement of Cash Flows

The following condensed consolidating balance sheets at March 31,2019 and December 31, 2018, condensed consolidating statements of operations for thethree months ended March 31,2019 and 2018and condensed consolidating statements of cash flows for thethree months ended March 31,2019 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.

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2019
		Parent		Subsidiary		Subsidiary			Consolidating
(in millions)		Issuer		Guarantors		Non-Guarantor			Entries			Total
Net cash flows provided by (used in) operating activities		$	(335)	$	958		$	-	$	-	$	623
Net cash flows used in investing activities			-		(902)			-		-		(902)
Net cash flows provided by (used in) financing activities			335		(56)			-		-		279
	Net increase 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
Three Months Ended March 31, 2018
		Parent		Subsidiary		Subsidiary			Consolidating
(in millions)		Issuer		Guarantors		Non-Guarantor			Entries			Total
Net cash flows provided by operating activities		$	351	$	137		$	-	$	-	$	488
Net cash flows used in investing activities			-		(93)			-		-		(93)
Net cash flows used in financing activities			(351)		(44)			-		-		(395)
	Net increase in cash and cash equivalents		-		-			-		-		-
	Cash and cash equivalents at beginning of period		-		-			-		-		-
	Cash and cash equivalents at end of period	$	-	$	-		$	-	$	-	$	-

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Subsequent Events (Tables)

3 Months Ended

Mar. 31, 2019

Subsequent Events [Abstract]

New commodity derivative contracts

After March 31,2019, the Company entered into the following derivative contractsto hedge additional amounts of estimated future production:

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Price Swaps: (a)
	2019:
		Volume (Bbl)		-		1,707,000		1,451,000		1,281,000		4,439,000
		Price per Bbl	$	-	$	62.64	$	63.14	$	63.43	$	63.03
	2021:
		Volume (Bbl)		1,170,000		1,183,000		1,196,000		1,196,000		4,745,000
		Price per Bbl	$	56.72	$	56.72	$	56.72	$	56.72	$	56.72
Oil Basis Swaps: (b)
	2019:
		Volume (Bbl)		-		-		92,000		920,000		1,012,000
		Price per Bbl	$	-	$	-	$	(1.05)	$	(0.07)	$	(0.16)
	2020:
		Volume (Bbl)		1,092,000		-		-		-		1,092,000
		Price per Bbl	$	0.10	$	-	$	-	$	-	$	0.10
	2021:
		Volume (Bbl)		540,000		546,000		552,000		552,000		2,190,000
		Price per Bbl	$	0.50	$	0.50	$	0.50	$	0.50	$	0.50
(a)	The oil derivative contracts are settled based on the NYMEX – WTI calendar-month average futures price.
(b)	The basis differential price is between Midland – WTI and Cushing – WTI. These contracts are settled on a calendar-month basis.

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Supplementary Information (Tables)

3 Months Ended

Mar. 31, 2019

Supplementary Information [Abstract]

Capitalized costs

Capitalized costs

			March 31,		December 31,
(in millions)			2019		2018
Oil and natural gas properties:
	Proved		$	26,000	$	24,992
	Unproved			6,559		6,714
	Less: accumulated depletion			(10,138)		(9,701)
		Net capitalized costs for oil and natural gas properties	$	22,421	$	22,005

Costs incurred for oil and natural gas producing activities

Costs incurred for oil and natural gas producing activities

		Three Months Ended
		March 31,
(in millions)		2019		2018
Property acquisition costs:
	Proved	$	-	$	-
	Unproved		4		13
Exploration			462		243
Development			464		207
	Total costs incurred for oil and natural gas properties	$	930	$	463

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Basis Of Presentation And Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($)		1 Months Ended		3 Months Ended
		Apr. 30, 2019	Feb. 28, 2018	Mar. 31, 2019	Mar. 31, 2018	Jan. 01, 2019	Dec. 31, 2018
Significant Accounting Policies Disclosure [Line Items]
Receivables related to contracts with customers				$ 530,000,000			$ 466,000,000
Fees related to operation of jointly owned oil and natural gas properties				4,000,000	$ 4,000,000
Right of use asset	[1]			33,000,000
Right of use asset, operating leases				18,000,000
Right of use asset, finance leases				15,000,000
Lease liabilities				$ 36,000,000
Accounting Standards Update 2018-01 [Member]
Significant Accounting Policies Disclosure [Line Items]
Cumulative effect adjustment						$ 0
Accounting Standards Update 2016-02 [Member]
Significant Accounting Policies Disclosure [Line Items]
Right of use asset						35,000,000
Right of use asset, operating leases						19,000,000
Right of use asset, finance leases						16,000,000
Lease liabilities						$ 37,000,000
Oryx Southern Delaware Holdings [Member]
Significant Accounting Policies Disclosure [Line Items]
Equity method investment ownership percentage				23.75%
Total distribution from equity method investment			$ 157,000,000
Portion of equity method investment distribution that offset Company's net investment			54,000,000
Total equity method investment				$ 0			$ 0
Income (loss) from equity method investments			103,000,000	$ 0
Oryx Southern Delaware Holdings [Member] | Disposal Group Heldforsale Not Discontinued Operations [Member] | Scenario Forecast [Member]
Significant Accounting Policies Disclosure [Line Items]
Equity method investment ownership percentage		23.75%
Percentage of interest sold		100.00%
Oryx Southern Delaware Holdings [Member] | Loans Payable [Member]
Significant Accounting Policies Disclosure [Line Items]
Face amount of debt			$ 800,000,000

[1] 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.

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RSP Acquisition (Narrative) (Details) - RSP Permian [Member] - USD ($) $ in Millions		3 Months Ended
	Jul. 19, 2018	Mar. 31, 2019
Business Acquisition [Line Items]
Acquisition close date		Jul. 19, 2018
Consideration paid	$ 7,549

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RSP Acquisition (Purchase Price Allocation) (Details) - USD ($) $ in Millions	Jul. 19, 2018	Mar. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Implied goodwill		$ 2,229	$ 2,224
RSP Permian [Member]
Business Acquisition [Line Items]
Total purchase price	$ 7,549
Accounts payable - trade	48
Accrued drilling costs	79
Current derivative instruments	10
Other current liabilities	124
Long-term debt	1,758
Deferred income taxes	514
Asset retirement obligations	20
Noncurrent derivative instruments	5
Total liabilities assumed	2,558
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	2,229
Total assets acquired	$ 10,107

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RSP Acquisition (Schedule Of Pro Forma Information) (Details) - RSP Permian [Member] $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($) $ / shares
Business Acquisition [Line Items]
Operating revenues | $	$ 1,226
Net income | $	$ 931
Earnings per share, Basic net income | $ / shares	$ 4.66
Earnings per share, Diluted net income | $ / shares	$ 4.64

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Other Aquisitions, Divestitures And Nonmonetary Transactions (Narrative) (Details) $ in Millions	1 Months Ended		3 Months Ended
	Feb. 28, 2018 USD ($) a	Jan. 31, 2018 USD ($) a	Mar. 31, 2019 USD ($)	Mar. 31, 2018 USD ($)
Business Acquisition [Line Items]
Pre-tax gain (loss)			$ 1	$ 723
February 2018 Acquisition Divestiture [Member]
Business Acquisition [Line Items]
Net acreage | a	21,000
Pre-tax gain (loss)				575
Fair value of acquired assets	$ 755
Book value of divested assets	$ 180
February 2018 Acquisition Divestiture [Member] | Disposal Group Disposed Of By Means Other Than Sale Not Discontinued Operations Exchange [Member]
Business Acquisition [Line Items]
Net acreage | a	34,000
Delaware Basin [Member]
Business Acquisition [Line Items]
Net acreage | a		20,000
Pre-tax gain (loss)				134
Net proceeds from divestiture		$ 280
Nonmonetary Transactions [Member]
Business Acquisition [Line Items]
Pre-tax gain (loss)				$ 14

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Stock incentive Plan (Narrative) (Details) - shares		1 Months Ended	3 Months Ended
		Jan. 31, 2019	Mar. 31, 2019
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards granted	[1]		235,082
Performance Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards granted		212,947	212,947	[2],[3]
Performance Units [Member] | Officer [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards granted		38,952
Performance Units [Member] | Three Year Vesting Period [Member] | Officer [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period			3 years
Awards granted		19,476
Vesting percentage		20.00%
Performance Units [Member] | Five Year Vesting Period [Member] | Officer [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period			5 years
Awards granted		19,476
Vesting percentage		20.00%
Other Performance Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period			3 years
Minimum [Member] | Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period			1 year
Maximum [Member] | Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period			10 years

[1] Weighted average grant date fair value per share is $105.52

[2] Includes 38,952 performance award units 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.

[3] Weighted average grant date fair value per unit is $144.03

XML

Stock Incentive Plan (Summary Of Restricted Stock Shares and Performance Unit Activity) (Details) - $ / shares		1 Months Ended	3 Months Ended
		Jan. 31, 2019	Mar. 31, 2019
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding at beginning of period		1,364,699	1,364,699
Awards granted	[1]		235,082
Awards cancelled / forfeited			(14,947)
Lapse of restrictions			(146,048)
Outstanding at end of period			1,438,786
Awards granted - Weighted average grant date fair value per share / unit			$ 105.52
Performance Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding at beginning of period		218,391	218,391
Awards granted		212,947	212,947	[2],[3]
Awards cancelled / forfeited			0
Lapse of restrictions			0
Outstanding at end of period			431,338
Awards granted - Weighted average grant date fair value per share / unit			$ 144.03

[1] Weighted average grant date fair value per share is $105.52

[2] Includes 38,952 performance award units 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.

[3] Weighted average grant date fair value per unit is $144.03

XML

Stock Incentive Plan (Summary For Future Stock-Based Compensation Expense) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 24	$ 17
Remaining 2019 And Thereafter [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	140
Remaining 2019 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	61
2020 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	48
2021 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	22
2022 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	4
2023 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	2
2024 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	1
Thereafter [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 2

XML

Disclosures About Fair Value Measurements (Carrying Amounts And Fair Values Of The Company's Financial Instruments) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2019	Dec. 31, 2018
Fair Value Disclosure Item Amounts [Domain] | 4.375% senior notes due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Face amount of debt		$ 600
Interest rate		4.375%
Debt maturity year		2025
Fair Value Disclosure Item Amounts [Domain] | 3.75% senior notes due 2027
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Face amount of debt		$ 1,000
Interest rate		3.75%
Debt maturity year		2027
Fair Value Disclosure Item Amounts [Domain] | 4.3% senior notes due 2028
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Face amount of debt		$ 1,000
Interest rate		4.30%
Debt maturity year		2028
Fair Value Disclosure Item Amounts [Domain] | 4.875% senior notes due 2047
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Face amount of debt		$ 800
Interest rate		4.875%
Debt maturity year		2047
Fair Value Disclosure Item Amounts [Domain] | 4.85% senior notes due 2048
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Face amount of debt		$ 600
Interest rate		4.85%
Debt maturity year		2048
Derivative instruments, Assets		$ 3	$ 695
Derivative instruments, Liabilities		367	0
Credit facility		615	242
4.375% senior notes due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes		617	591
Face amount of debt	[1]	$ 600	$ 600
Interest rate		4.375%	4.375%
Debt maturity year		2025
3.75% senior notes due 2027
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes		$ 991	$ 939
Face amount of debt		$ 1,000	$ 1,000
Interest rate		3.75%	3.75%
Debt maturity year		2027
4.3% senior notes due 2028
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes		$ 1,033	$ 980
Face amount of debt		$ 1,000	$ 1,000
Interest rate		4.30%	4.30%
Debt maturity year		2028
4.875% senior notes due 2047
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes		$ 849	$ 761
Face amount of debt		$ 800	$ 800
Interest rate		4.875%	4.875%
Debt maturity year		2047
4.85% senior notes due 2048
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes		$ 634	$ 573
Face amount of debt		$ 600	$ 600
Interest rate		4.85%	4.85%
Debt maturity year		2048
Carrying Reported Amount Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Derivative instruments, Assets		$ 3	$ 695
Derivative instruments, Liabilities		367	0
Credit facility		615	242
Carrying Reported Amount Fair Value Disclosure [Member] | 4.375% senior notes due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes	[2]	594	594
Carrying Reported Amount Fair Value Disclosure [Member] | 3.75% senior notes due 2027
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes	[2]	989	989
Carrying Reported Amount Fair Value Disclosure [Member] | 4.3% senior notes due 2028
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes	[2]	988	988
Carrying Reported Amount Fair Value Disclosure [Member] | 4.875% senior notes due 2047
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes	[2]	789	789
Carrying Reported Amount Fair Value Disclosure [Member] | 4.85% senior notes due 2048
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes	[2]	$ 592	$ 592

[1] 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.

[2] The carrying value includes associated deferred loan costs and any discount.

XML

Disclosures About Fair Value Measurements (Company's Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative, Fair Value, Net	$ (364)	$ 695
Commodity Derivative [Member] | Derivative Asset Current [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	57	543
Derivative Asset, Fair Value, Gross Liability	(56)	(59)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	1	484
Commodity Derivative [Member] | Derivative Asset Noncurrent [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	29	243
Derivative Asset, Fair Value, Gross Liability	(27)	(32)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	2	211
Commodity Derivative [Member] | Derivative Liability Current [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Liability, Fair Value, Gross Liability	(348)	(59)
Derivative Liability, Fair Value, Gross Asset	56	59
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(292)	0
Commodity Derivative [Member] | Derivative Liability Noncurrent [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Liability, Fair Value, Gross Liability	(102)	(32)
Derivative Liability, Fair Value, Gross Asset	27	32
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(75)	0
Fair Value Inputs Level 1 [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative, Fair Value, Net	0	0
Fair Value Inputs Level 1 [Member] | Commodity Derivative [Member] | Derivative Asset Current [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Fair Value Inputs Level 1 [Member] | Commodity Derivative [Member] | Derivative Asset Noncurrent [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Fair Value Inputs Level 1 [Member] | Commodity Derivative [Member] | Derivative Liability Current [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value Inputs Level 1 [Member] | Commodity Derivative [Member] | Derivative Liability Noncurrent [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value Inputs Level 2 [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative, Fair Value, Net	(364)	695
Fair Value Inputs Level 2 [Member] | Commodity Derivative [Member] | Derivative Asset Current [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	57	543
Fair Value Inputs Level 2 [Member] | Commodity Derivative [Member] | Derivative Asset Noncurrent [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	29	243
Fair Value Inputs Level 2 [Member] | Commodity Derivative [Member] | Derivative Liability Current [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Liability, Fair Value, Gross Liability	(348)	(59)
Fair Value Inputs Level 2 [Member] | Commodity Derivative [Member] | Derivative Liability Noncurrent [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Liability, Fair Value, Gross Liability	(102)	(32)
Fair Value Inputs Level 3 [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative, Fair Value, Net	0	0
Fair Value Inputs Level 3 [Member] | Commodity Derivative [Member] | Derivative Asset Current [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Fair Value Inputs Level 3 [Member] | Commodity Derivative [Member] | Derivative Asset Noncurrent [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Fair Value Inputs Level 3 [Member] | Commodity Derivative [Member] | Derivative Liability Current [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value Inputs Level 3 [Member] | Commodity Derivative [Member] | Derivative Liability Noncurrent [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 0	$ 0

XML

Derivative Financial Instruments (Summary Of The Gains And Losses Reported In Earnings Related To The Commodity Derivative Instruments) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Financial Instruments Gains And Losses Reported In Earnings Related To Commodity And Interest Rate Derivative Instruments [Line Items]
Gain (loss) on derivatives	$ (1,059)	$ (35)
Net settlements received from (paid on) derivatives	0	(112)
Oil Commodity Derivative [Member]
Derivative Financial Instruments Gains And Losses Reported In Earnings Related To Commodity And Interest Rate Derivative Instruments [Line Items]
Gain (loss) on derivatives	(1,056)	(33)
Net settlements received from (paid on) derivatives	3	(113)
Natural Gas Commodity Derivative [Member]
Derivative Financial Instruments Gains And Losses Reported In Earnings Related To Commodity And Interest Rate Derivative Instruments [Line Items]
Gain (loss) on derivatives	(3)	(2)
Net settlements received from (paid on) derivatives	$ (3)	$ 1

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Derivative Financial Instruments (Outstanding Commodity Derivative Contracts) (Details)	3 Months Ended
	Mar. 31, 2019 MMBTU $ / bbl $ / MMBTU bbl
Oil Price Swaps 2019 [Member]
Derivative [Line Items]
Volume | bbl	39,722,750	[1]
Price	56.33	[1]
Oil Price Swaps Q2 2019 [Member]
Derivative [Line Items]
Volume | bbl	15,112,750	[1]
Price	56.59	[1]
Oil Price Swaps Q3 2019 [Member]
Derivative [Line Items]
Volume | bbl	13,378,000	[1]
Price	56.41	[1]
Oil Price Swaps Q4 2019 [Member]
Derivative [Line Items]
Volume | bbl	11,232,000	[1]
Price	55.88	[1]
Oil Price Swaps 2020 [Member]
Derivative [Line Items]
Volume | bbl	39,340,000	[1]
Price	57.21	[1]
Oil Price Swaps Q1 2020 [Member]
Derivative [Line Items]
Volume | bbl	10,502,500	[1]
Price	57.28	[1]
Oil Price Swaps Q2 2020 [Member]
Derivative [Line Items]
Volume | bbl	10,166,500	[1]
Price	57.24	[1]
Oil Price Swaps Q3 2020 [Member]
Derivative [Line Items]
Volume | bbl	9,453,000	[1]
Price	57.18	[1]
Oil Price Swaps Q4 2020 [Member]
Derivative [Line Items]
Volume | bbl	9,218,000	[1]
Price	57.14	[1]
Oil Price Swaps 2021 [Member]
Derivative [Line Items]
Volume | bbl	8,392,000	[1]
Price	54.54	[1]
Oil Price Swaps Q1 2021 [Member]
Derivative [Line Items]
Volume | bbl	2,160,000	[1]
Price	54.57	[1]
Oil Price Swaps Q2 2021 [Member]
Derivative [Line Items]
Volume | bbl	2,184,000	[1]
Price	54.57	[1]
Oil Price Swaps Q3 2021 [Member]
Derivative [Line Items]
Volume | bbl	2,024,000	[1]
Price	54.5	[1]
Oil Price Swaps Q4 2021 [Member]
Derivative [Line Items]
Volume | bbl	2,024,000	[1]
Price	54.5	[1]
Oil Costless Collars 2019 [Member]
Derivative [Line Items]
Volume | bbl	3,406,250	[1]
Oil Costless Collars 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Price	55.76	[1]
Oil Costless Collars 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Price	63.5	[1]
Oil Costless Collars Q2 2019 [Member]
Derivative [Line Items]
Volume | bbl	1,213,250	[1]
Oil Costless Collars Q2 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Price	56.06	[1]
Oil Costless Collars Q2 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Price	64	[1]
Oil Costless Collars Q3 2019 [Member]
Derivative [Line Items]
Volume | bbl	1,135,000	[1]
Oil Costless Collars Q3 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Price	55.74	[1]
Oil Costless Collars Q3 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Price	63.47	[1]
Oil Costless Collars Q4 2019 [Member]
Derivative [Line Items]
Volume | bbl	1,058,000	[1]
Oil Costless Collars Q4 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Price	55.43	[1]
Oil Costless Collars Q4 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Price	62.95	[1]
Oil Basis Swaps 2019 [Member]
Derivative [Line Items]
Volume | bbl	39,748,500	[2]
Price	(2.69)	[2]
Oil Basis Swaps Q2 2019 [Member]
Derivative [Line Items]
Volume | bbl	11,965,500	[2]
Price	(3.03)	[2]
Oil Basis Swaps Q3 2019 [Member]
Derivative [Line Items]
Volume | bbl	12,650,000	[2]
Price	(2.82)	[2]
Oil Basis Swaps Q4 2019 [Member]
Derivative [Line Items]
Volume | bbl	15,133,000	[2]
Price	(2.32)	[2]
Oil Basis Swaps 2020 [Member]
Derivative [Line Items]
Volume | bbl	43,445,000	[2]
Price	(0.65)	[2]
Oil Basis Swaps Q1 2020 [Member]
Derivative [Line Items]
Volume | bbl	13,013,000	[2]
Price	(0.53)	[2]
Oil Basis Swaps Q2 2020 [Member]
Derivative [Line Items]
Volume | bbl	10,192,000	[2]
Price	(0.7)	[2]
Oil Basis Swaps Q3 2020 [Member]
Derivative [Line Items]
Volume | bbl	10,120,000	[2]
Price	(0.71)	[2]
Oil Basis Swaps Q4 2020 [Member]
Derivative [Line Items]
Volume | bbl	10,120,000	[2]
Price	(0.71)	[2]
Oil Basis Swaps 2021 [Member]
Derivative [Line Items]
Volume | bbl	8,395,000	[2]
Price	0.55	[2]
Oil Basis Swaps Q1 2021 [Member]
Derivative [Line Items]
Volume | bbl	2,070,000	[2]
Price	0.55	[2]
Oil Basis Swaps Q2 2021 [Member]
Derivative [Line Items]
Volume | bbl	2,093,000	[2]
Price	0.55	[2]
Oil Basis Swaps Q3 2021 [Member]
Derivative [Line Items]
Volume | bbl	2,116,000	[2]
Price	0.55	[2]
Oil Basis Swaps Q4 2021 [Member]
Derivative [Line Items]
Volume | bbl	2,116,000	[2]
Price	0.55	[2]
Natural Gas Price Swaps 2019 [Member]
Derivative [Line Items]
Energy | MMBTU	51,749,459	[3]
Price | $ / MMBTU	2.87	[3]
Natural Gas Price Swaps Q2 2019 [Member]
Derivative [Line Items]
Energy | MMBTU	17,241,387	[3]
Price | $ / MMBTU	2.87	[3]
Natural Gas Price Swaps Q3 2019 [Member]
Derivative [Line Items]
Energy | MMBTU	17,298,537	[3]
Price | $ / MMBTU	2.87	[3]
Natural Gas Price Swaps Q4 2019 [Member]
Derivative [Line Items]
Energy | MMBTU	17,209,535	[3]
Price | $ / MMBTU	2.87	[3]
Natural Gas Price Swaps 2020 [Member]
Derivative [Line Items]
Energy | MMBTU	24,703,000	[3]
Price | $ / MMBTU	2.7	[3]
Natural Gas Price Swaps Q1 2020 [Member]
Derivative [Line Items]
Energy | MMBTU	6,233,500	[3]
Price | $ / MMBTU	2.7	[3]
Natural Gas Price Swaps Q2 2020 [Member]
Derivative [Line Items]
Energy | MMBTU	6,233,500	[3]
Price | $ / MMBTU	2.7	[3]
Natural Gas Price Swaps Q3 2020 [Member]
Derivative [Line Items]
Energy | MMBTU	6,118,000	[3]
Price | $ / MMBTU	2.7	[3]
Natural Gas Price Swaps Q4 2020 [Member]
Derivative [Line Items]
Energy | MMBTU	6,118,000	[3]
Price | $ / MMBTU	2.7	[3]

[1] The oil derivative contracts are settled based on the NYMEX – West Texas Intermediate (“WTI”) calendar-month average futures price.

[2] 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.

[3] The natural gas derivative contracts are settled based on the NYMEX – Henry Hub last trading day futures price.

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Debt (Narrative) (Details) - Credit Facility [Member] $ in Billions	3 Months Ended
	Mar. 31, 2019 USD ($)
Debt Disclosure [Line Items]
Line of credit maturity date	May 09, 2022
Aggregate lender commitments	$ 2.0
Unused lender commitments	$ 1.4
Debt weighted average interest rate	4.40%

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Debt (Summary Of Long-Term Debt) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Credit facility		$ 615	$ 242
Unamortized original issue premium (discount), net		(10)	(10)
Senior notes issuance costs, net		(38)	(38)
Less: current portion		0	0
Total long-term debt		4,567	4,194
4.375% senior notes due 2025
Debt Instrument [Line Items]
Unsecured senior notes	[1]	$ 600	$ 600
Interest rate		4.375%	4.375%
Debt maturity year		2025
4.375% senior notes due 2025 | January 15, 2020 [Member]
Debt Instrument [Line Items]
Callable price		103.281%
4.375% senior notes due 2025 | January 15, 2021 [Member]
Debt Instrument [Line Items]
Callable price		102.188%
4.375% senior notes due 2025 | January 15, 2022 [Member]
Debt Instrument [Line Items]
Callable price		101.094%
4.375% senior notes due 2025 | January 15, 2023 [Member]
Debt Instrument [Line Items]
Callable price		100.00%
3.75% senior notes due 2027
Debt Instrument [Line Items]
Unsecured senior notes		$ 1,000	$ 1,000
Interest rate		3.75%	3.75%
Debt maturity year		2027
4.3% senior notes due 2028
Debt Instrument [Line Items]
Unsecured senior notes		$ 1,000	$ 1,000
Interest rate		4.30%	4.30%
Debt maturity year		2028
4.875% senior notes due 2047
Debt Instrument [Line Items]
Unsecured senior notes		$ 800	$ 800
Interest rate		4.875%	4.875%
Debt maturity year		2047
4.85% senior notes due 2048
Debt Instrument [Line Items]
Unsecured senior notes		$ 600	$ 600
Interest rate		4.85%	4.85%
Debt maturity year		2048

[1] 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.

XML

Debt (Summary Of Interest Expense) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disclosure Debt Summary Of Interest Expense [Abstract]
Cash payments for interest	$ 63	$ 18
Non-cash interest	1	1
Net changes in accruals	(13)	12
Interest costs incurred	51	31
Less: capitalized interest	(4)	(1)
Total interest expense	$ 47	$ 30

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Commitments And Contingencies (Narrative) (Details)	3 Months Ended
	Mar. 31, 2019 USD ($) bbl / d	Mar. 31, 2018 USD ($)
Commitments [Line Items]
Gross lease cost related to short-term leases	$ 94,000,000
Short-term lease costs capitalized	$ 67,000,000
Operating leases, lease payments		$ 3,000,000
May 2018 Commitment [Member]
Commitments [Line Items]
Commitment term	1 year
Shortfall makeup period	2 months
May 2018 Commitment [Member] | Minimum [Member]
Commitments [Line Items]
Daily production commitment (barrels per day) | bbl / d	7,000
January 2019 Commitment [Member]
Commitments [Line Items]
Commitment term	5 years
Daily production commitment (barrels per day) | bbl / d	50,000

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Commitments And Contingencies (Summary Of The Company's Future Commitments) (Details) $ in Millions	Mar. 31, 2019 USD ($)
Oil And Gas Delivery Commitments And Contracts [Line Items]
Remaining 2019	$ 35
2020	75
2021	76
2022	36
2023	33
2024	34
Thereafter	96
Total	$ 385

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Commitments And Contingencies (Oil And Natural Gas Delivery Commitments) (Details) Mcf in Thousands, bbl in Millions	3 Months Ended
	Mar. 31, 2019 bbl Mcf
Oil [Member]
Long Term Purchase Commitment [Line Items]
Remaining 2019 | bbl	12
2020 | bbl	36
2021 | bbl	39
2022 | bbl	41
2023 | bbl	33
2024 | bbl	33
Thereafter | bbl	114
Total | bbl	308
Natural Gas [Member]
Long Term Purchase Commitment [Line Items]
Remaining 2019 | Mcf	2,697
2020 | Mcf	10,286
2021 | Mcf	21,627
2022 | Mcf	16,425
2023 | Mcf	16,425
2024 | Mcf	16,470
Thereafter | Mcf	32,850
Total | Mcf	116,780

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Commitments And Contingencies (Supplemental Balance Sheet Information Related To Leases) (Details) $ in Millions	Mar. 31, 2019 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Operating lease right-of-use assets	$ 18
Finance lease right-of-use assets	15
Total lease right-of-use assets	33	[1]
Current operating lease liabilities	7
Current finance lease liabilities	6
Noncurrent operating lease liabilities	13
Noncurrent finance lease laibilities	10
Total lease liabilities	$ 36

[1] 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.

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Commitments And Contingencies (Components Of Lease Expense) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Lessee Lease Description [Line Items]
Finance lease cost	$ 2	[1]
Net lease cost	4
General And Administrative [Member]
Lessee Lease Description [Line Items]
Operating lease cost	$ 2

[1] Interest on lease liabilities related to finance leases was immaterial during the three months ended March 31, 2019.

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Commitments And Contingencies (Supplemental Cash Flow Information Related To Leases) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Cash paid for amounts included in measurement of lease liabilities, Operating cash flows from operating leases	$ 2
Cash paid for amounts included in measurement of lease liabilities, Financing cash flows from finance leases	2
Right-of-use assets obtained in exchange for lease obligations, Operating leases	0
Right-of-use assets obtained in exchange for lease obligations, Finance leases	$ 3

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Commitments And Contingencies (Lease Terms And Discount Rates Related To Leases) (Details)	Mar. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Weighted average remaining lease term, Operating leases	3 years 6 months
Weighted average remaining lease term, Finance leases	2 years 10 months 24 days
Weighted average discount rate, Operating leases	4.90%
Weighted average discount rate, Finance leases	4.40%

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Commitments And Contingencies (Maturity Of Lease Liabilities) (Details) $ in Millions	Mar. 31, 2019 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Remaining 2019	$ 6
Operating Leases, 2020	8
Operating Leases, 2021	6
Operating Leases, 2022	1
Operating Leases, Thereafter	1
Operating Leases, Total lease payments	22
Finance Leases, Remaining 2019	5
Finance Leases, 2020	6
Finance Leases, 2021	4
Finance Leases, 2022	2
Finance Leases, Thereafter	0
Finance Leases, Total lease payments	$ 17

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Commitments and Contingencies (Present Value Of Lease Liabilities) (Details) $ in Millions	Mar. 31, 2019 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Total lease payments	$ 22
Operating Leases, Less: Interest	(2)
Operating Leases, Present value of lease liabilities	20
Finance Leases, Total lease payments	17
Finance Leases, Less: Interest	(1)
Finance Leases, Present value of lease liabilities	$ 16

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Commitments And Contingencies (Future Minimum Lease Commitments Under Non-Cancellable Operating Leases) (Details) $ in Millions	Dec. 31, 2018 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2019	$ 14
2020	12
2021	10
2022	3
2023	0
Thereafter	1
Total	$ 40

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Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Disclosure Income Taxes Narrative [Abstract]
Income tax (expense) benefit	$ 194	$ (254)
Discrete income tax expense (benefit)	$ (2)	$ (2)
Effective tax rate	22.00%	23.00%
Unrecognized tax benefits that would impact effective tax rate			$ 63
Increase in unrecongized tax benefits for current year	$ 16

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Related Party Transactions (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Related Party Transaction [Line Items]
Amounts paid	$ 6	$ 1
Director [Member]
Related Party Transaction [Line Items]
Ownership interest in partnership	3.50%

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Earnings Per Share (Narrative) (Details) - Performance Units [Member]	3 Months Ended
	Mar. 31, 2019
Minimum [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Vesting period	3 years
Vesting percentage	0.00%
Maximum [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Vesting period	5 years
Vesting percentage	300.00%

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Earnings Per Share (Reconciliation Of Earnings Attributable To Common Shares Basic And Diluted) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
Earnings Per Share Reconciliation [Abstract]
Net income (loss) as reported		$ (695)	$ 835
Participating basic earnings	[1]	0	(6)
Basic earnings (loss) attributable to common stockholders		(695)	829
Reallocation of participating earnings		0	0
Diluted earnings (loss) attributable to common stockholders		$ (695)	$ 829

[1] 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.

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Earnings Per Share (Reconciliation Of The Weighted Average Common Shares Outstanding) (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disclosure Net Income Per Share Reconciliation Of The Weighted Average Common Shares Outstanding [Abstract]
Basic	199,148	147,925
Dilutive performance shares	0	537
Diluted	199,148	148,462

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Earnings Per Share (Summary Of The Common Stock Options And Restricted Stock) (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Performance Units [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive common shares	324	0

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Subsidiary Guarantors (Condensed Consolidating Balance Sheet) (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
ASSETS
Accounts receivable - related parties	$ 0	$ 0
Other current assets	1,027	1,409
Oil and natural gas properties, net	22,421	22,005
Property and equipment, net	350	308
Investment in subsidiaries	0	0
Goodwill	2,229	2,224
Other long-term assets	141	348
Total assets	26,168	26,294
LIABILITIES AND EQUITY
Accounts payable - related parties	0	0
Other current liabilities	1,660	1,356
Long-term debt	4,567	4,194
Other long-term liabilities	1,882	1,976
Equity	18,059	18,768	$ 9,738	$ 8,915
Total liabilities and stockholders' equity	26,168	26,294
Consolidating Entries [Member]
ASSETS
Accounts receivable - related parties	(18,518)	(18,155)
Other current assets	0	0
Oil and natural gas properties, net	0	0
Property and equipment, net	0	0
Investment in subsidiaries	(5,629)	(5,411)
Goodwill	0	0
Other long-term assets	0	0
Total assets	(24,147)	(23,566)
LIABILITIES AND EQUITY
Accounts payable - related parties	(18,518)	(18,155)
Other current liabilities	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Equity	(5,629)	(5,411)
Total liabilities and stockholders' equity	(24,147)	(23,566)
Parent Company [Member] | Reportable Legal Entities [Member]
ASSETS
Accounts receivable - related parties	18,518	18,155
Other current assets	6	534
Oil and natural gas properties, net	0	0
Property and equipment, net	0	0
Investment in subsidiaries	5,629	5,411
Goodwill	0	0
Other long-term assets	15	224
Total assets	24,168	24,324
LIABILITIES AND EQUITY
Accounts payable - related parties	0	0
Other current liabilities	368	70
Long-term debt	4,567	4,194
Other long-term liabilities	1,174	1,292
Equity	18,059	18,768
Total liabilities and stockholders' equity	24,168	24,324
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
ASSETS
Accounts receivable - related parties	0	0
Other current assets	1,021	875
Oil and natural gas properties, net	22,405	21,988
Property and equipment, net	350	308
Investment in subsidiaries	0	0
Goodwill	2,229	2,224
Other long-term assets	126	124
Total assets	26,131	25,519
LIABILITIES AND EQUITY
Accounts payable - related parties	18,502	18,138
Other current liabilities	1,292	1,286
Long-term debt	0	0
Other long-term liabilities	708	684
Equity	5,629	5,411
Total liabilities and stockholders' equity	26,131	25,519
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
ASSETS
Accounts receivable - related parties	0	0
Other current assets	0	0
Oil and natural gas properties, net	16	17
Property and equipment, net	0	0
Investment in subsidiaries	0	0
Goodwill	0	0
Other long-term assets	0	0
Total assets	16	17
LIABILITIES AND EQUITY
Accounts payable - related parties	16	17
Other current liabilities	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Equity	0	0
Total liabilities and stockholders' equity	$ 16	$ 17

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Subsidiary Guarantors (Condensed Consolidating Statement Of Operations) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Condensed Financial Statements Captions [Line Items]
Total operating revenues	$ 1,104	$ 947
Total operating costs and expenses	(1,950)	68
Income (loss) from operations	(846)	1,015
Interest expense	(47)	(30)
Other, net	4	104
Income (loss) before income taxes	(889)	1,089
Income tax (expense) benefit	194	(254)
Net income (loss)	(695)	835
Consolidation Eliminations [Member]
Condensed Financial Statements Captions [Line Items]
Total operating revenues	0	0
Total operating costs and expenses	0	0
Income (loss) from operations	0	0
Interest expense	0	0
Other, net	(218)	(1,153)
Income (loss) before income taxes	(218)	(1,153)
Income tax (expense) benefit	0	0
Net income (loss)	(218)	(1,153)
Parent Company [Member] | Reportable Legal Entities [Member]
Condensed Financial Statements Captions [Line Items]
Total operating revenues	0	0
Total operating costs and expenses	(1,060)	(34)
Income (loss) from operations	(1,060)	(34)
Interest expense	(47)	(30)
Other, net	218	1,153
Income (loss) before income taxes	(889)	1,089
Income tax (expense) benefit	194	(254)
Net income (loss)	(695)	835
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Financial Statements Captions [Line Items]
Total operating revenues	1,104	942
Total operating costs and expenses	(890)	105
Income (loss) from operations	214	1,047
Interest expense	0	0
Other, net	4	104
Income (loss) before income taxes	218	1,151
Income tax (expense) benefit	0	0
Net income (loss)	218	1,151
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Financial Statements Captions [Line Items]
Total operating revenues	0	5
Total operating costs and expenses	0	(3)
Income (loss) from operations	0	2
Interest expense	0	0
Other, net	0	0
Income (loss) before income taxes	0	2
Income tax (expense) benefit	0	0
Net income (loss)	$ 0	$ 2

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Subsidiary Guarantors (Condensed Consolidating Statement Of Cash Flows) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Condensed Financial Statements Captions [Line Items]
Net cash provided by (used in) operating activities	$ 623	$ 488
Net cash flows provided by (used in) investing activities	(902)	(93)
Net cash flows provided by (used in) financing activities	279	(395)
Net increase in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
Consolidation Eliminations [Member]
Condensed Financial Statements Captions [Line Items]
Net cash provided by (used in) operating activities	0	0
Net cash flows provided by (used in) investing activities	0	0
Net cash flows provided by (used in) financing activities	0	0
Net increase in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
Parent Company [Member] | Reportable Legal Entities [Member]
Condensed Financial Statements Captions [Line Items]
Net cash provided by (used in) operating activities	(335)	351
Net cash flows provided by (used in) investing activities	0	0
Net cash flows provided by (used in) financing activities	335	(351)
Net increase in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Financial Statements Captions [Line Items]
Net cash provided by (used in) operating activities	958	137
Net cash flows provided by (used in) investing activities	(902)	(93)
Net cash flows provided by (used in) financing activities	(56)	(44)
Net increase in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Financial Statements Captions [Line Items]
Net cash provided by (used in) operating activities	0	0
Net cash flows provided by (used in) investing activities	0	0
Net cash flows provided by (used in) financing activities	0	0
Net increase in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	$ 0	$ 0

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Subsequent Events (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended
	Apr. 30, 2019	Apr. 30, 2019	Mar. 31, 2019
Subsequent Event [Line Items]
Dividends declared, amount per share			$ 0.125
Subsequent Event [Member]
Subsequent Event [Line Items]
Dividends declared, date declared	Apr. 30, 2019
Dividends declared, amount per share	$ 0.125	$ 0.125
Dividends declared, date payable	Jun. 28, 2019
Dividends declared, date of record	May 10, 2019
Oryx Southern Delaware Holdings [Member]
Subsequent Event [Line Items]
Equity method investment ownership percentage			23.75%
Beta Holding [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Equity method investment ownership percentage	50.00%	50.00%
Transportation agreement period		10 years
Disposal Group Heldforsale Not Discontinued Operations [Member] | Oryx Southern Delaware Holdings [Member] | Scenario Forecast [Member]
Subsequent Event [Line Items]
Percentage of interest sold		100.00%
Proceeds from the sale of equity investment		$ 300
Equity method investment ownership percentage	23.75%	23.75%

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Subsequent Events (New Commodity Derivative Contracts) (Details)			3 Months Ended
		May 01, 2019 $ / bbl bbl	Mar. 31, 2019 $ / bbl bbl
Oil Price Swaps 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[1]		39,722,750
Price | $ / bbl	[1]		56.33
Oil Price Swaps Q2 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[1]		15,112,750
Price | $ / bbl	[1]		56.59
Oil Price Swaps Q3 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[1]		13,378,000
Price | $ / bbl	[1]		56.41
Oil Price Swaps Q4 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[1]		11,232,000
Price | $ / bbl	[1]		55.88
Oil Price Swaps 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[1]		8,392,000
Price | $ / bbl	[1]		54.54
Oil Price Swaps Q1 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[1]		2,160,000
Price | $ / bbl	[1]		54.57
Oil Price Swaps Q2 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[1]		2,184,000
Price | $ / bbl	[1]		54.57
Oil Price Swaps Q3 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[1]		2,024,000
Price | $ / bbl	[1]		54.5
Oil Price Swaps Q4 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[1]		2,024,000
Price | $ / bbl	[1]		54.5
Oil Basis Swaps 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[2]		39,748,500
Price | $ / bbl	[2]		(2.69)
Oil Basis Swaps Q3 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[2]		12,650,000
Price | $ / bbl	[2]		(2.82)
Oil Basis Swaps Q4 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[2]		15,133,000
Price | $ / bbl	[2]		(2.32)
Oil Basis Swaps 2020 [Member]
Subsequent Event [Line Items]
Volume | bbl	[2]		43,445,000
Price | $ / bbl	[2]		(0.65)
Oil Basis Swaps Q1 2020 [Member]
Subsequent Event [Line Items]
Volume | bbl	[2]		13,013,000
Price | $ / bbl	[2]		(0.53)
Oil Basis Swaps 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[2]		8,395,000
Price | $ / bbl	[2]		0.55
Oil Basis Swaps Q1 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[2]		2,070,000
Price | $ / bbl	[2]		0.55
Oil Basis Swaps Q2 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[2]		2,093,000
Price | $ / bbl	[2]		0.55
Oil Basis Swaps Q3 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[2]		2,116,000
Price | $ / bbl	[2]		0.55
Oil Basis Swaps Q4 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[2]		2,116,000
Price | $ / bbl	[2]		0.55
Subsequent Event [Member] | Oil Price Swaps 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[3]	4,439,000
Price | $ / bbl	[3]	63.03
Subsequent Event [Member] | Oil Price Swaps Q2 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[3]	1,707,000
Price | $ / bbl	[3]	62.64
Subsequent Event [Member] | Oil Price Swaps Q3 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[3]	1,451,000
Price | $ / bbl	[3]	63.14
Subsequent Event [Member] | Oil Price Swaps Q4 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[3]	1,281,000
Price | $ / bbl	[3]	63.43
Subsequent Event [Member] | Oil Price Swaps 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[3]	4,745,000
Price | $ / bbl	[3]	56.72
Subsequent Event [Member] | Oil Price Swaps Q1 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[3]	1,170,000
Price | $ / bbl	[3]	56.72
Subsequent Event [Member] | Oil Price Swaps Q2 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[3]	1,183,000
Price | $ / bbl	[3]	56.72
Subsequent Event [Member] | Oil Price Swaps Q3 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[3]	1,196,000
Price | $ / bbl	[3]	56.72
Subsequent Event [Member] | Oil Price Swaps Q4 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[3]	1,196,000
Price | $ / bbl	[3]	56.72
Subsequent Event [Member] | Oil Basis Swaps 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[4]	1,012,000
Price | $ / bbl	[4]	(0.16)
Subsequent Event [Member] | Oil Basis Swaps Q3 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[4]	92,000
Price | $ / bbl	[4]	(1.05)
Subsequent Event [Member] | Oil Basis Swaps Q4 2019 [Member]
Subsequent Event [Line Items]
Volume | bbl	[4]	920,000
Price | $ / bbl	[4]	(0.07)
Subsequent Event [Member] | Oil Basis Swaps 2020 [Member]
Subsequent Event [Line Items]
Volume | bbl	[4]	1,092,000
Price | $ / bbl	[4]	0.1
Subsequent Event [Member] | Oil Basis Swaps Q1 2020 [Member]
Subsequent Event [Line Items]
Volume | bbl	[4]	1,092,000
Price | $ / bbl	[4]	0.1
Subsequent Event [Member] | Oil Basis Swaps 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[4]	2,190,000
Price | $ / bbl	[4]	0.5
Subsequent Event [Member] | Oil Basis Swaps Q1 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[4]	540,000
Price | $ / bbl	[4]	0.5
Subsequent Event [Member] | Oil Basis Swaps Q2 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[4]	546,000
Price | $ / bbl	[4]	0.5
Subsequent Event [Member] | Oil Basis Swaps Q3 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[4]	552,000
Price | $ / bbl	[4]	0.5
Subsequent Event [Member] | Oil Basis Swaps Q4 2021 [Member]
Subsequent Event [Line Items]
Volume | bbl	[4]	552,000
Price | $ / bbl	[4]	0.5

[1] The oil derivative contracts are settled based on the NYMEX – West Texas Intermediate (“WTI”) calendar-month average futures price.

[2] 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.

[3] The oil derivative contracts are settled based on the NYMEX – WTI calendar-month average futures price.

[4] The basis differential price is between Midland – WTI and Cushing – WTI. These contracts are settled on a calendar-month basis.

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Supplementary information (Capitalized Costs) (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Supplementary Information [Abstract]
Proved	$ 26,000	$ 24,992
Unproved	6,559	6,714
Less: accumulated depletion	(10,138)	(9,701)
Net capitalized costs for oil and natural gas properties	$ 22,421	$ 22,005

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Supplementary Information (Costs Incurred For Oil And Natural Gas Producing Activities) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Supplementary Information [Abstract]
Proved	$ 0	$ 0
Unproved	4	13
Exploration	462	243
Development	464	207
Total costs incurred for oil and natural gas properties	$ 930	$ 463