Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2018	Feb. 15, 2019	Jun. 30, 2018
Document Documentand Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
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 Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		200,594,232
Entity Public Float			$ 20,433,760,692

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 0	$ 0
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas	466	331
Joint operations and other	365	212
Inventory	35	14
Derivative instruments	484	0
Prepaid costs and other	59	35
Total current assets	1,409	592
Property and equipment:
Oil and natural gas properties, successful efforts method	31,706	21,267
Accumulated depletion and depreciation	(9,701)	(8,460)
Total oil and natural gas properties, net	22,005	12,807
Other property and equipment, net	308	234
Total property and equipment, net	22,313	13,041
Deferred loan costs, net	10	13
Goodwill	2,224	0
Intangible assets, net	19	26
Noncurrent derivative instruments	211	0
Other assets	108	60
Total assets	26,294	13,732
Current liabilities:
Accounts payable - trade	50	43
Bank overdrafts	159	116
Revenue payable	253	183
Accrued drilling costs	574	330
Derivative instruments	0	277
Other current liabilities	320	216
Total current liabilities	1,356	1,165
Long-term debt	4,194	2,691
Deferred income taxes	1,808	687
Noncurrent derivative instruments	0	102
Asset retirement obligations and other long-term liabilities	168	172
Commitments and contingencies (Note 11)
Stockholders' equity:
Common stock, $0.001 par value; 300,000,000 authorized; 201,288,884 and 149,324,849 shares issued at December 31, 2018 and 2017, respectively	0	0
Additional paid-in capital	14,773	7,142
Retained earnings	4,126	1,840
Treasury stock, at cost; 1,031,655 and 598,049 shares at December 31, 2018 and 2017, respectively	(131)	(67)
Total stockholders' equity	18,768	8,915
Total liabilities and stockholders' equity	$ 26,294	$ 13,732

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
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	201,288,884	149,324,849
Treasury shares	1,031,655	598,049

Consolidated Statements of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating revenues:
Total operating revenues	$ 4,151	$ 2,586	$ 1,635
Operating costs and expenses:
Production and ad valorem taxes	305	199	131
Exploration and abandonments	65	59	77
Depreciation, depletion and amortization	1,478	1,146	1,167
Accretion of discount on asset retirement obligations	10	8	7
Impairments of long-lived assets	0	0	1,525
General and administrative (including non-cash stock-based compensation of $82, $60 and $59 for the years ended December 31, 2018, 2017 and 2016, respectively)	311	244	226
(Gain) loss on derivatives	(832)	126	369
Gain on disposition of assets, net	(800)	(678)	(118)
Transaction costs	39	3	5
Total operating costs and expenses	1,221	1,515	3,709
Income (loss) from operations	2,930	1,071	(2,074)
Other income (expense):
Interest expense	(149)	(146)	(204)
Loss on extinguishment of debt	0	(66)	(56)
Other, net	108	22	(4)
Total other expense	(41)	(190)	(264)
Income (loss) before income taxes	2,889	881	(2,338)
Income tax (expense) benefit	(603)	75	876
Net income (loss)	$ 2,286	$ 956	$ (1,462)
Earnings per share:
Basic net income (loss)	$ 13.28	$ 6.44	$ (10.85)
Diluted net income (loss)	$ 13.25	$ 6.41	$ (10.85)
Oil [Member]
Operating revenues:
Total operating revenues	$ 3,443	$ 2,092	$ 1,350
Natural Gas [Member]
Operating revenues:
Total operating revenues	708	494	285
Oil And Natural Gas Production [Member]
Operating costs and expenses:
Operating costs and expenses	590	408	320
Gathering, Processing and Transportation
Operating costs and expenses:
Operating costs and expenses	$ 55	$ 0	$ 0

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement [Abstract]
Non-cash stock-based compensation	$ 82	$ 60	$ 59

Consolidated Statement 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, Shares at Dec. 31, 2015		129,444			306
BALANCE at Dec. 31, 2015	$ 6,943	$ 0	$ 4,629	$ 2,346	$ (32)
Net income (loss)	(1,462)	$ 0	0	(1,462)	$ 0
Issuance of common stock (Shares)		10,350			0
Issuance of common stock	1,327	$ 0	1,327	0	$ 0
Common stock issued in business combinations (Shares)		6,134
Common stock issued in business combinations	768	$ 0	768
Stock options exercised	1	$ 0	1	0	$ 0
Stock options exercised, shares		23
Grants of restricted stock, shares		451			0
Performance unit share conversion, shares		180
Cancellation of restricted stock, shares		(93)			0
Stock-based compensation	59	$ 0	59	0	$ 0
Tax deficiency related to stock-based compensation	(1)	0	(1)	0	0
Purchase of treasury stock	(12)	$ 0	0	0	$ (12)
Purchase of treasury stock, shares		0			124
BALANCE, Shares at Dec. 31, 2016		146,489			430
BALANCE at Dec. 31, 2016	7,623	$ 0	6,783	884	$ (44)
Adoption of ASU 2016-09 (Note 2)	8	0	8	0	0
BALANCE at Jan. 1, 2017	7,631	0	6,791	884	(44)
Net income (loss)	956	$ 0	0	956	$ 0
Common stock issued in business combinations (Shares)		2,177			0
Common stock issued in business combinations	291	$ 0	291	0	$ 0
Stock options exercised	0	$ 0	0	0	$ 0
Stock options exercised, shares		20			0
Grants of restricted stock, shares		490			0
Performance unit share conversion, shares		249			0
Cancellation of restricted stock, shares		(100)			0
Stock-based compensation	60	$ 0	60	0	$ 0
Purchase of treasury stock	(23)	$ 0	0	0	$ (23)
Purchase of treasury stock, shares		0			168
BALANCE, Shares at Dec. 31, 2017		149,325			598
BALANCE at Dec. 31, 2017	8,915	$ 0	7,142	1,840	$ (67)
Net income (loss)	2,286	$ 0	0	2,286	$ 0
Common stock issued in business combinations (Shares)		50,915			0
Common stock issued in business combinations	7,549	$ 0	7,549	0	$ 0
Grants of restricted stock, shares		687			0
Performance unit share conversion, shares		447			0
Cancellation of restricted stock, shares		(85)			0
Stock-based compensation	82	$ 0	82	0	$ 0
Purchase of treasury stock	(64)	$ 0	0	0	$ (64)
Purchase of treasury stock, shares		0			434
BALANCE, Shares at Dec. 31, 2018		201,289			1,032
BALANCE at Dec. 31, 2018	$ 18,768	$ 0	$ 14,773	$ 4,126	$ (131)

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 2,286	$ 956	$ (1,462)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	1,478	1,146	1,167
Accretion of discount on asset retirement obligations	10	8	7
Impairments of long-lived assets	0	0	1,525
Exploration and abandonments, including dry holes	35	27	57
Non-cash stock-based compensation expense	82	60	59
Deferred income taxes	605	(71)	(864)
Gain on disposition of assets, net	(800)	(678)	(118)
(Gain) loss on derivatives	(832)	126	369
Net settlements received from (paid on) derivatives	(218)	79	625
Loss on extinguishment of debt	0	66	56
Other	(92)	(1)	14
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable	(35)	(126)	32
Prepaid costs and other	(10)	(9)	6
Inventory	(12)	0	2
Accounts payable	1	14	15
Revenue payable	52	52	(38)
Other current liabilities	8	46	(68)
Net cash provided by operating activities	2,558	1,695	1,384
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and natural gas properties	(2,496)	(1,581)	(1,046)
Acquisitions of oil and natural gas properties	(136)	(908)	(1,351)
Additions to property, equipment and other assets	(90)	(44)	(61)
Proceeds from the disposition of assets	361	803	332
Deposits on dispositions of oil and natural gas properties	0	29	0
Direct transaction costs for disposition of assets	(3)	(18)	0
Funds held in escrow	0	0	(43)
Contributions to equity method investments	0	0	(56)
Distribution from equity method investment	148	0	0
Net cash used in investing activities	(2,216)	(1,719)	(2,225)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	3,316	1,001	0
Payments on credit facility	(3,396)	(679)	0
Issuance of senior notes, net	1,595	1,794	600
Repayments of senior notes	0	(2,150)	(1,200)
Repayments of RSP debt	(1,690)	0	0
Debt extinguishment costs	(83)	(63)	(42)
Excess tax deficiency from stock-based compensation	0	0	(1)
Net proceeds from issuance of common stock	0	0	1,327
Payments for loan costs	(16)	(25)	(7)
Purchase of treasury stock	(64)	(23)	(12)
Increase (decrease) in bank overdrafts	(4)	116	0
Net cash provided by (used in) financing activities	(342)	(29)	665
Net decrease in cash and cash equivalents	0	(53)	(176)
Cash and cash equivalents at beginning of period	0	53	229
Cash and cash equivalents at end of period	0	0	53
SUPPLEMENTAL CASH FLOWS:
Cash paid for interest	118	139	232
Cash paid for income taxes	2	13	0
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Issuance of common stock for business combinations	$ 7,549	$ 291	$ 768

Organization and nature of operations	12 Months Ended
Organization and nature of operations	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [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 Southeast New Mexico and West Texas.

Summary of significant accounting policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Summary of significant accounting policies

Note 2. Summary of significant accounting policies

Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The consolidated financial statements also included the accounts of a variable interest entity (“VIE”) where the Company was the primary beneficiary of the arrangements until the VIE structure dissolved in January 2018. See Note 5 for additional information regarding the circumstances surrounding the VIE. 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 2018 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 GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, 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.

Cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

Accounts receivable. The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Oil and natural gas sales receivables related to these operations are generally unsecured. Joint interest receivables are generally secured pursuant to the operating agreement between or among the co-owners of the operated property. The Company determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and the Company’s ability to realize the receivables through netting of anticipated future production revenues. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The Company had an allowance for doubtful accounts of approximately $5 million and $1 million for the years ended December 31, 2018 and 2017, respectively.

Inventory. Inventory consists primarily of tubular goods, water and other oilfield equipment that the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of weighted average cost or net realizable value.

Oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized leasehold costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized drilling and development costs and integrated assets is based on the unit-of-production method using proved developed reserves. The Company recognized depletion expense of $1.5 billion, $1.1 billion and $1.1 billion during the years ended December 31, 2018, 2017 and 2016, respectively.

The Company generally does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:

the well has found a sufficient quantity of reserves to justify its completion as a producing well; and
the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the Company’s large multi-well project development program, capital intensive nature and geographical location of certain projects, it may take longer than one year to evaluate the future potential of the exploration well and economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. The Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves and is transferred to proved oil and natural gas properties or is noncommercial and is charged to exploration and abandonments expense. See Note 3 for additional information regarding the Company’s exploratory well costs.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire depletion base is sold. However, gain or loss is recognized from the sale of less than an entire depletion base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. Ordinary maintenance and repair costs are expensed as incurred.

Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed. The Company capitalizes interest on expenditures for significant development projects until such projects are ready for their intended use. During the years ended December 31, 2018 and 2017, the Company had capitalized interest of approximately $9 million and $3 million, respectively. The Company did not have capitalized interest related to significant oil and natural gas development projects for the year ended December 31, 2016.

The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by depletion base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties and integrated assets would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs and cash flows from integrated assets. The Company did not recognize impairment expense during the years ended December 31, 2018 and 2017. The Company recognized impairment expense of approximately $1.5 billion during the year ended December 31, 2016 related to its proved oil and natural gas properties. See Note 8 for additional information regarding the Company’s impairment expense.

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects. During the years ended December 31, 2018, 2017 and 2016, the Company recognized expense of approximately $35 million, $27 million and $50 million, respectively, related to abandoned and expiring acreage, which is included in exploration and abandonments expense in the accompanying consolidated statements of operations.

Other property and equipment. Other capital assets include buildings, transportation equipment, computer equipment and software, telecommunications equipment, leasehold improvements and furniture and fixtures. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two to 39 years. The Company had other capital assets of $308 million and $234 million, net of accumulated depreciation of $109 million and $90 million, at December 31, 2018 and December 31, 2017, respectively. During the years ended December 31, 2018, 2017 and 2016, the Company recognized depreciation expense of $22 million, $21 million and $21 million, respectively.

Goodwill. As a result of the RSP Acquisition, as defined in Note 4, the Company has goodwill in the amount of $2.2 billion at December 31, 2018. Goodwill is not amortized but assessed for impairment on an annual basis, or more frequently if indicators of impairment exist. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed as of July 1 of each year. The balance of goodwill is allocated in its entirety to the Company’s one reporting unit. When testing goodwill for impairment, the Company first performs a qualitative analysis to determine if it is more likely than not that the fair value of its reporting unit is less than its carrying value. If the analysis shows that the fair value is more likely than not less than the carrying value, then the Company performs a quantitative impairment test. The Company early adopted Accounting Standards Update (“ASU”) No. 2017-04, “Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (“ASU 2017-04”). Per ASU 2017-04, if the results of the quantitative test are such that the fair value of the reporting unit is less than the carrying value, goodwill is reduced by an amount that is equal to the amount by which the carrying value of the reporting unit exceeds the fair value. Because of the recent decline in the price of oil and the volatility of the Company’s common stock, the Company performed an analysis at December 31, 2018 and determined that it was not more likely than not that the fair value of its reporting unit was less than its carrying value. As a result, the Company did not recognize impairment expense during the year ended December 31, 2018.

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 December 31, 2018, 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 and approximately $49 million at December 31, 2018 and 2017, respectively. The Company recorded income of approximately $4 million and $7 million for the years ended December 31, 2018 and 2017, respectively. The Company will not record income or loss on the Oryx investment until such net income is greater than the distribution in excess of its investment.

On December 26, 2018, the Company contributed certain infrastructure assets to WaterBridge Operating LLC (“WaterBridge”), an entity that operates and manages various water infrastructure assets located in the Permian Basin, in exchange for, among other consideration, 100,000 Series A-1 Preferred Units (“Preferred Units”). The Preferred Units contain certain redemption rights, incentives and restrictions, as specified in the agreement. The Company accounts for the investment using the equity method. In conjunction with the transaction, the Company entered into a water management services agreement with WaterBridge. The Company had no amounts due to WaterBridge at December 31, 2018. The Company’s investment in WaterBridge is recorded in other assets in the Company’s consolidated balance sheets.

In February 2017, the Company closed on the divestiture of its 50 percent membership interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), that constructed a crude oil gathering and transportation system in the Delaware Basin. See Note 5 for additional information regarding the disposition of ACC.

Regulatory and environmental compliance. The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Regulatory liabilities relate to acquisitions where additional equipment is necessary to have facilities compliant with local, state and federal obligations and are capitalized. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures that are noncapital in nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Environmental liabilities normally involve estimates that are subject to revisions until settlement occurs. See Note 11 for additional information.

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 11 for additional information.

Income taxes. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. At December 31, 2018, the Company had unrecognized tax benefits of approximately $63 million, primarily related to research and development credits. 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. The Company has not recognized any interest or penalties relating to unrecognized tax benefits in its consolidated financial statements. Any interest or penalties would be recognized as a component of income tax expense.

On December 22, 2017, the President of the United States (the “President”) signed into law the tax bill commonly referred to as the “Tax Cuts and Job Act” (“TCJA”), significantly changing federal income tax laws. According to the Accounting Standards Codification (“ASC”) section 740, “Income Taxes,” (“ASC 740”), a company is required to record the effects of an enacted tax law or rate change in the period of enactment, which is the date the bill is signed by the President and becomes law. As a result of the enactment of the TCJA, the U.S. Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” (“SAB 118”) to provide guidance for companies that have not completed the accounting for the income tax effects of the TCJA in the period of enactment. SAB 118 allowed companies to report provisional amounts when based on reasonable estimates and to adjust these amounts during a measurement period of up to one year. The Company elected to apply SAB 118 and, as such, recorded provisional amounts for the income tax balances reported in its consolidated financial statements at December 31, 2017. At December 31, 2018, the Company completed its accounting for all tax effects of the TCJA and made an adjustment to its provisional amounts related to the deductibility of certain compensation based on available regulatory and interpretive guidance. See Note 12 for additional information regarding the Company’s deferred tax balances and the impacts of the TCJA.

Derivative instruments. The Company recognizes its derivative instruments, other than commodity derivative contracts that are designated as normal purchase and normal sale contracts, as either assets or liabilities measured at fair value. The Company nets the fair value of the derivative instruments by counterparty in the accompanying consolidated balance sheets when the right of offset exists. The Company does not have any derivatives designated as fair value or cash flow hedges. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated balance sheets.

Asset retirement obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related oil and natural gas property asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are recognized as an increase in the carrying amount of the liability through accretion expense. Based on certain factors, including commodity prices and costs, the Company may revise its previous estimates of the liability, which would also increase or decrease the related oil and natural gas property asset.

Treasury stock. Treasury stock purchases are recorded at cost.

Revenue recognition. On January 1, 2018, the Company adopted ASC Topic 606, “Revenue from Contracts with Customers,” (“ASC 606”) using the modified retrospective approach, which only applies to contracts that were not completed as of the date of initial application. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment and does not have a material impact on the Company’s reported net income (loss), cash flows from operations or statement of stockholders’ equity.

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. Prior to the adoption of ASC 606, the Company recorded oil and natural gas revenues at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. The Company followed the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.

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 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 December 31, 2018, the Company had receivables related to contracts with customers of approximately $466 million.

The following table shows the impact of the adoption of ASC 606 on the Company’s current period results as compared to the previous revenue recognition standard, ASC Topic 605, “Revenue recognition” (“ASC 605”):


		Year Ended
		December 31, 2018
		Under		Under		Increase
(in millions)		ASC 606		ASC 605		(Decrease)

Operating revenues:
	Oil sales	$	3,443	$	3,432	$	11
	Natural gas sales		708		674		34

Operating costs and expenses:
	Oil and natural gas production		590		600		(10)
	Gathering, processing and transportation		55		-		55

Net income		$	2,286	$	2,286	$	-

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 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 reductions of general and administrative expense. Such fees totaled approximately $19 million, $16 million and $17 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Stock-based compensation. Stock-based compensation expense is recognized in the Company’s financial statements on an accelerated basis over the awards’ vesting periods based on their grant date fair values. Stock-based compensation awards vest over a period generally ranging from one to five years. The Company utilizes the average of the high and low stock prices at each grant date to determine the fair value of restricted stock and the Monte Carlo simulation method to determine the fair value of performance unit awards. The Company recognizes forfeitures on stock-based compensation awards as they occur. When the Company adopted ASU No. 2016-09, “Compensation–Stock Compensation (Topic 718): Improvements to Employee Share-based Payment Accounting,” (“ASU 2016-09”) on January 1, 2017, it recorded a cumulative effect adjustment, which decreased retained earnings by less than $1 million, increased additional paid-in capital by approximately $8 million and decreased net deferred income tax liabilities by approximately $8 million.

Recently adopted accounting pronouncements. In January 2017, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2017-04, which simplifies how an entity subsequently measures goodwill by eliminating Step 2 from the goodwill impairment test. In place of Step 2, an entity will recognize an impairment charge for the amount by which the carrying amount of a reporting unit exceeds its fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to the reporting unit. The Company early adopted this standard beginning in the third quarter of 2018. The adoption of this standard did not have an impact on the Company’s financial results.

In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as asset acquisitions or as business combinations. The guidance provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the acquired assets is concentrated in a single asset or a group of similar assets, the set is not a business. If the screen is not met, to be considered a business, the set must include an input and a substantive process that together significantly contribute to the ability to create output. The Company adopted this standard on January 1, 2018. See Notes 4 and 5 for information regarding the Company’s significant acquisitions and divestitures.

New accounting pronouncements issued but not yet adopted. In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)” (“ASU 2016-02”), which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for financing and operating leases. Lease expense recognition on the consolidated statements of operations will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018. The Company made policy elections to not capitalize short-term leases for all asset classes and to not separate non-lease components from lease components for all asset classes except for vehicles. The Company also plans to not elect the package of practical expedients that allows for certain considerations under the original “Leases (Topic 840)” accounting standard (“Topic 840”) to be carried forward upon adoption of ASU 2016-02.

The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, well equipment and drilling rigs. The Company has completed the process of reviewing and determining the contracts to which this new guidance applies. Upon adoption, on January 1, 2019, the Company recognized approximately $35 million of right-of-use assets, of which approximately $19 million and $16 million relate to the Company’s operating and financing leases, respectively, and approximately $37 million of associated lease liabilities that are not currently recognized under applicable guidance.

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 to not 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 will elect this practical expedient, which becomes effective upon the date of adoption of ASU 2016-02. After the 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 to not 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.

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 July 2018, the FASB issued ASU No. 2018-09, “Codification Improvements,” (“ASU 2018-09”) which makes amendments to multiple codification topics to clarify, correct errors in, or make minor improvements to the accounting standards codification. The effective date of the standard is dependent on the facts and circumstances of each amendment. Some amendments do not require transition guidance and will be effective upon the issuance of this standard. Many of the amendments in ASU 2018-09 will be effective in annual periods beginning after December 15, 2018. The Company will be required to adopt this standard in the first quarter of fiscal 2019. The Company is currently assessing the effect that this ASU will have on the financial position, results of operations, and disclosures.

On August 17, 2018, the 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 to interim periods the annual disclosure requirement in SEC Regulation S-X, Rule 3-04, of presenting changes in stockholders’ equity. The registrants will be 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. The final rule became effective for all filings submitted on or after November 5, 2018.

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.

Exploratory well costs

12 Months Ended

Dec. 31, 2018

Disclosure Exploratory Well Costs Capitalized Exploratory Well Activity [Abstract]

Exploratory well costs

Note 3. Exploratory well costs

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are carried in unproved oil and natural gas properties. See Unaudited Supplementary Data for the proved and unproved components of oil and natural gas properties. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments expense in the consolidated statements of operations.

The following table reflects the Company’s net capitalized exploratory well activity during each of the years ended December 31, 2018, 2017 and 2016:


		Years Ended December 31,
(in millions)		2018		2017		2016

Beginning capitalized exploratory well costs		$	182	$	151	$	116
	Additions to exploratory well costs pending the determination of proved reserves (a)		581		180		144
	Reclassifications due to determination of proved reserves		(226)		(147)		(86)
	Exploratory well costs charged to expense		-		-		(6)
	Disposition of wells		(14)		(2)		(17)
Ending capitalized exploratory well costs		$	523	$	182	$	151


(a)	Includes $82 million of exploratory well costs acquired as part of the RSP Acquisition, as defined in Note 4.

The following table provides an aging at December 31, 2018 and 2017 of capitalized exploratory well costs based on the date drilling was completed:


			December 31,
(in millions, except number of projects)			2018		2017

Capitalized exploratory well costs that have been capitalized for a period of one year or less		$	523	$	180
Capitalized exploratory well costs that have been capitalized for a period greater than one year			-		2
	Total capitalized exploratory well costs	$	523	$	182
Number of projects with exploratory well costs that have been capitalized for a period greater
	than one year		-		2

RSP acquisition

12 Months Ended

Dec. 31, 2018

RSP Acquisition [Abstract]

RSP Acquisition

Note 4. RSP Acquisition

On July 19, 2018, the Company completed the acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”). RSP was an independent oil and natural gas company engaged in the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of RSP’s acreage was located on large, contiguous acreage blocks in the core of the Midland Basin and the Delaware Basin. The acquisition added approximately 92,000 net acres. Under the terms of the Agreement and Plan of Merger (the “Acquisition Agreement”), each share of RSP common stock was converted into 0.320 of a share of the Company’s common stock. The Company issued approximately 51 million shares of common stock at a price of $148.27 per share, resulting in total consideration paid by the Company to the former RSP shareholders of approximately $7.5 billion.

In connection with the closing of the RSP Acquisition, the Company repaid outstanding principal under RSP’s revolving credit facility and redeemed and canceled all of RSP’s outstanding unsecured senior notes. See Note 10 for additional information regarding the Company’s debt activity.

In connection with the RSP Acquisition, the Company incurred approximately $32 million of costs related to consulting, investment banking, advisory, legal and other acquisition-related fees during the year ended December 31, 2018, which are included in transaction costs in operating costs and expenses on the consolidated statements of operations. In addition, the Company acquired 670,369 shares of common stock from RSP employees for the payment of withholding taxes due on the vesting of their restricted shares pursuant to the Acquisition Agreement, resulting in an increase of approximately $32 million in the Company’s treasury stock balance.

Purchase price allocation. The RSP Acquisition has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary 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 expected to be deductible for income tax purposes. Certain data necessary to complete the purchase price allocation is not yet available, including tax return data from RSP’s short period ending July 19, 2018 that provides underlying tax basis in assets and liabilities and uncertain tax positions.

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			74
	Current derivative instruments			10
	Other current liabilities			124
	Long-term debt			1,758
	Deferred income taxes			515
	Asset retirement obligations			20
	Noncurrent derivative instruments			5
		Total liabilities assumed	$	2,554

		Total purchase price plus liabilities assumed	$	10,103

Fair value of assets acquired:
	Accounts receivable		$	194
	Current derivative instruments			36
	Other current assets			22
	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			2,224
		Total assets acquired	$	10,103

The fair values of assets acquired and liabilities assumed were based on the following key inputs:

Oil and natural gas properties

The fair value of proved and unproved oil and natural gas properties was measured using valuation techniques that convert the future cash flows to a single discounted amount. Significant inputs to the valuation of proved and unproved oil and natural gas properties include estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average costs of capital. The Company utilized a combination of the NYMEX strip pricing and consensus pricing, adjusted for differentials, to value the reserves. The Company’s estimates of commodity prices for purposes of determining discounted cash flows ranged from a 2018 price of $66.59 per barrel of oil decreasing to a 2022 price of $63.41 per barrel of oil. Similarly, natural gas prices ranged from a 2018 price of $2.80 per MMBtu then rising to a 2022 price of $3.09 per MMBtu. Both oil and natural gas commodity prices were held flat after 2022 and adjusted for inflation. The Company then applied various discount rates depending on the classification of reserves and other risk characteristics. Management utilized the assistance of a third-party valuation expert to estimate the value of the oil and natural gas properties acquired.

The fair value of asset retirement obligations totaled $20 million and is included in proved oil and natural gas properties with a corresponding liability in the table above. The fair value was determined based on a discounted cash flow model, which included assumptions of the estimated current abandonment costs, discount rate, inflation rate and timing associated with the incurrence of these costs.

The inputs used to value oil and natural gas properties and asset retirement obligations require significant judgment and estimates made by management and represent Level 3 inputs.

Financial instruments and other

The fair value measurements of long-term debt were estimated based on the market prices and represent Level 1 inputs. The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves, implied market volatility, contract terms and prices and discount factors as of the close date of the RSP Acquisition and represent Level 2 inputs. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk and the derivative instruments in a liability position include a measure of the Company’s own nonperformance risk, each based on the current published credit default swap rates.

The fair values determined for accounts receivable, accounts payable – trade, accrued drilling costs and other current liabilities were equivalent to the carrying value due to their short-term nature.

Other current liabilities include approximately $16 million of liabilities primarily related to certain regulatory obligations.

Deferred income taxes

The RSP Acquisition qualified as a tax-free merger whereby the Company acquired carryover tax basis in RSP’s assets and liabilities, adjusted for differences between the purchase price allocated to the assets acquired and liabilities assumed based on the fair value and the carryover tax basis. See Note 12 for additional discussion of deferred income taxes.

Goodwill recognized is primarily attributable to the following factors: (i) operating and administrative synergies and (ii) net deferred tax liabilities arising from the differences between the purchase price allocated to RSP’s assets and liabilities based on fair value and the tax basis of these assets and liabilities. For the operating and administrative synergies, the total consideration for the RSP Acquisition included a control premium, which resulted in a higher value compared to the fair value of net assets acquired. There are also other qualitative assumptions of long-term factors that the RSP Acquisition creates for the Company’s stockholders, including additional potential for exploration and development opportunities and additional scale and efficiencies in basins in which the Company operates.

Approximately $506 million of operating revenues and approximately $274 million of income from operations attributed to the RSP Acquisition are included in the Company’s results of operations from the closing date on July 19, 2018 through December 31, 2018.

Pro forma data. The following unaudited pro forma combined condensed financial data for the years ended December 31, 2018 and 2017 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 gas properties and (iii) the estimated tax impacts of the pro forma adjustments.

Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $32 million for the year ended December 31, 2018 and acquisition-related costs incurred by RSP and severance payments to certain RSP employees that totaled approximately $56 million for the year ended December 31, 2018. 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.


		Years Ended December 31,
(in millions, except per share amounts)		2018		2017
		(unaudited)

Operating revenues		$	4,798	$	3,390
Net income		$	2,552	$	1,197
Earnings per share:
	Basic net income	$	12.75	$	6.02
	Diluted net income	$	12.73	$	5.99

Acquisitions, divestitures and nonmonetary transactions

12 Months Ended

Dec. 31, 2018

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

Acquisitions, divestitures and nonmonetary transactions

Note 5. Acquisitions, divestitures and nonmonetary transactions

During the year ended December 31, 2018, the Company closed on the following transactions (exclusive of the RSP Acquisition disclosed in Note 4):

February 2018 acquisition and divestiture. In February 2018, the Company closed on an acquisition treated as a business combination where it received producing wells with approximately 5 MBoepd along with approximately 21,000 net acres, primarily located in the Midland Basin. As consideration for the non-cash acquisition, the Company divested approximately 34,000 net acres, primarily comprised of approximately 32,000 net acres in the northern Delaware Basin, with production of 3 MBoepd. 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. The fair value of the assets acquired totaled approximately $755 million, which was comprised of approximately $245 million of proved properties, approximately $480 million of unproved properties and approximately $30 million of other assets. The fair value of the assets received in the business combination approximated the fair value of assets disposed.

Delaware Basin divestitures. In January 2018, the Company closed on two asset sales transactions 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 year ended December 31, 2018. The assets divested included proved and unproved oil and natural gas properties on approximately 20,000 net acres.

These divestitures completed a transaction structured as a reverse like-kind exchange (“Reverse 1031 Exchange”) in accordance with Section 1031 of the Internal Revenue Code of 1986, as amended, that the Company entered into concurrent with its July 2017 Midland Basin acquisition, as further described below.

Upon completion of the Reverse 1031 Exchange in January 2018, the assets and liabilities attributable to the acquisition that were held by the VIE were conveyed to the Company, and the VIE structure was dissolved.

Nonmonetary transactions. During 2018, the Company completed multiple nonmonetary transactions. These transactions included exchanges of both proved and unproved oil and natural gas properties. Certain of these transactions were accounted for at fair value and, as a result, the Company recorded pre-tax gains of approximately $15 million.

During the year ended December 31, 2017, the Company closed on the following transactions:

Delaware Basin acquisition. In January and April 2017, the Company closed on the two-part acquisition in the northern Delaware Basin. As consideration for the entire acquisition, the Company paid approximately $160 million in cash, of which $43 million was held in escrow at December 31, 2016, and issued to the seller approximately 2.2 million shares of its common stock with an approximate value of $291 million.

ACC divestiture. In February 2017, the Company closed on the divestiture of its ownership interest in ACC. The Company and its joint venture partner entered into separate agreements to sell 100 percent of their respective ownership interests in ACC. After adjustments for debt and working capital, the Company received cash proceeds from the sale of approximately $801 million. After direct transaction costs, the Company recorded a pre-tax gain on disposition of assets of approximately $655 million which is included in gain on disposition of assets, net on its consolidated statement of operations for the year ended December 31, 2017. The Company’s net investment in ACC at the time of closing was approximately $129 million.

Midland Basin acquisition. In July 2017, the Company completed an acquisition in the Midland Basin. As consideration for the acquisition, the Company paid approximately $595 million in cash.

Concurrent with the acquisition, the Company entered into a transaction structured as a Reverse 1031 Exchange. In connection with the Reverse 1031 Exchange, the Company assigned the ownership of the oil and natural gas properties acquired to a VIE formed by an exchange accommodation titleholder. The Company operates the properties pursuant to a management agreement with the VIE. At December 31, 2017, the Company was determined to be the primary beneficiary of the VIE, as the Company had the ability to control the activities that most significantly impact the VIE’s economic performance. The assets held by the VIE attributable to the acquisition were conveyed to the Company and the VIE structure terminated upon the completion of the Reverse 1031 Exchange. At December 31, 2017, the VIE’s total assets and liabilities included in the Company’s consolidated balance sheet were approximately $608 million and $604 million, respectively.

Nonmonetary transactions. During 2017, the Company completed multiple nonmonetary transactions. The 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 totaling approximately $26 million.

During the year ended December 31, 2016, the Company closed on the following transactions:

Asset divestiture. In February 2016, the Company sold certain assets in the northern Delaware Basin for proceeds of approximately $292 million and recognized a pre-tax gain of approximately $110 million.

Delaware Basin acquisition. In March 2016, the Company completed an acquisition of 80 percent of a third-party seller’s interest in certain oil and natural gas properties and related assets in the southern Delaware Basin. As consideration for the acquisition, the Company issued to the seller approximately 2.2 million shares of common stock with an approximate value of $231 million, $146 million in cash and $40 million to carry a portion of the seller’s future development costs in these properties that was expended in 2016 and 2017 and included in costs incurred.

Reliance acquisition. In October 2016, the Company completed an acquisition of approximately 40,000 net acres in the Midland Basin and other assets from Reliance Energy, Inc. (collectively, the “Reliance Acquisition”) for approximately $1.7 billion. As consideration for the acquisition, the Company paid approximately $1.2 billion in cash and issued to the seller approximately 3.9 million shares of common stock with an approximate value of $0.5 billion.

Approximately $29 million of operating revenues and approximately $10 million of income from operations attributed to the Reliance Acquisition are included in the Company’s results of operations from the closing date in October 2016 through the year ended December 31, 2016.

Pro forma data. The following unaudited pro forma combined condensed financial data for the year ended December 31, 2016 was derived from the historical financial statements of the Company giving effect to the Reliance Acquisition, as if it had occurred on January 1, 2016. The results of operations for the Reliance Acquisition are included in the Company’s results of operations since the closing date in October 2016 through December 31, 2018. 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 Reliance Acquisition taken place on January 1, 2016 and is not intended to be a projection of future results.


		Year Ended
(in millions, except per share amounts)		December 31, 2016
		(unaudited)

Operating revenues		$	1,717
Net loss		$	(1,396)
Earnings per common share:
	Basic net loss	$	(10.36)
	Diluted net loss	$	(10.36)

Asset retirement obligations

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

Note 6. Asset retirement obligations

The Company’s asset retirement obligations represent the estimated present value of the estimated cash flows the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company’s credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations.

The Company’s asset retirement obligation transactions during the years ended December 31, 2018, 2017 and 2016 are summarized in the table below:


		Years Ended December 31,
(in millions)			2018		2017		2016

Asset retirement obligations, beginning of period		$	141	$	130	$	120
	Liabilities incurred from new wells		4		2		2
	Liabilities assumed in acquisitions		26		10		13
	Accretion expense		10		8		7
	Disposition of wells		(4)		(1)		(11)
	Liabilities settled upon plugging and abandoning wells		(7)		(5)		(1)
	Revision of estimates (a)		9		(3)		-
Asset retirement obligations, end of period		$	179	$	141	$	130


(a)	The revision to the Companyʼs asset retirement obligation estimates for the year ended December 31, 2018 is primarily due to an increase in pad reclamation costs in New Mexico.

Incentive plans

12 Months Ended

Dec. 31, 2018

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

Incentive plans

Note 7. Incentive plans

Defined contribution plan. The Company sponsors a 401(k) defined contribution plan for the benefit of its employees. During the years ended December 31, 2018, 2017 and 2016, the Company matched 100 percent of employee contributions, not to exceed 10 percent of the employee’s annual eligible compensation, subject to federal limits. The Company’s contributions to the plan for the years ended December 31, 2018, 2017 and 2016 were approximately $12 million, $10 million and $9 million, respectively.

Stock incentive plan. The Company’s 2015 Stock Incentive Plan (the “Plan”) provides for granting stock options, restricted stock awards and performance awards to directors, officers and employees of the Company. A total of 10.5 million shares of common stock have been authorized for issuance under the Plan. At December 31, 2018, the Company had 1.4 million shares of common stock available for future grants. Shares issued as a result of awards granted under the Plan are generally new common shares.

Restricted stock awards. All restricted shares are legally issued and outstanding. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and cancelled and are no longer considered issued and outstanding. A summary of the Company’s restricted stock award activity for the year ended December 31, 2018 is presented below:


				Weighted
				Average
		Number of		Grant Date
		Restricted		Fair Value
		Shares		Per Share

Outstanding at December 31, 2017		1,149,246			$	118.02
	Shares granted	686,996	(a)		$	137.31
	Shares cancelled / forfeited	(85,228)			$	125.86
	Lapse of restrictions	(386,315)			$	115.06
Outstanding at December 31, 2018		1,364,699			$	128.08


(a)	Includes 167,122 restricted shares granted to RSP employees on July 20, 2018 that became employees of the Company.
(a)

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

The following table summarizes information about stock-based compensation for the Company’s restricted stock awards activity under the Plan for years ended December 31, 2018, 2017 and 2016:


		Years Ended December 31,
(in millions)			2018		2017		2016

Fair value for awards granted during the period (a)		$	94	$	60	$	51

Fair value for awards vested during the period		$	54	$	49	$	45

Stock-based compensation expense from restricted stock		$	60	$	43	$	41

Income tax benefit related to restricted stock		$	14	$	11	$	15


(a)	The weighted average grant date fair value per share amounts were $137.31, $123.16 and $112.78 for the years ended December 31, 2018, 2017 and 2016, respectively.
(a)

Performance unit awards. During the years ended December 31, 2018, 2017 and 2016, the Company awarded performance units to its officers under the Plan. The number of shares of common stock that will ultimately be issued will be determined by a combination of (i) comparing the Company’s total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. The performance period is 36 months. The grant date fair value was determined using the Monte Carlo simulation method and is being expensed ratably over the performance period. Expected volatilities utilized in the model were estimated using a historical period consistent with the remaining performance period of approximately three years. The risk-free interest rate was based on the U.S. Treasury rate for a term commensurate with the expected life of the grant.

The Company used the following assumptions to estimate the fair value of performance unit awards granted during the years ended December 31, 2018, 2017 and 2016:


	Years Ended December 31,
	2018	2017	2016

Risk-free interest rate	2.00%	1.47%	1.31%
Range of volatilities	23.5% - 64.0%	24.8% - 60.2%	31.6% - 59.0%

The following table summarizes the performance unit activity for the year ended December 31, 2018:


			Number of		Grant Date
			Units		Fair Value

Performance units:

	Outstanding at December 31, 2017		247,647	$	146.10
		Units granted (a)	111,490	$	216.03
		Lapse of restrictions (b)	(140,746)	$	114.81
	Outstanding at December 31, 2018		218,391	$	201.97


(a)	Reflects the amount of performance units granted. The actual payout of shares will be between zero and 300 percent of the performance units granted depending on the Company’s performance at the end of the performance period.
(a)
(b)	On December 31, 2018, the performance period ended for these performance units. Each unit converted into 1.75 shares representing 246,314 shares of common stock issued on January 2, 2019.
(b)

The following table summarizes information about stock-based compensation expense for performance units for the years ended December 31, 2018, 2017 and 2016:


		Years Ended December 31,
(in millions)			2018		2017		2016

Fair value for awards granted during the period (a)		$	24	$	20	$	19

Fair value for awards vested during the period		$	68	$	68	$	33

Stock-based compensation expense from performance units		$	22	$	17	$	18

Income tax benefit related to performance units		$	14	$	2	$	7


(a)	The weighted average grant date fair value per unit amounts were $216.03, $183.48 and $114.81 for the years ended December 31, 2018, 2017 and 2016, respectively.
(a)

On January 1, 2017, the Company adopted ASU 2016-09 and elected to account for forfeitures of share-based payments as they occur. During the years ended December 31, 2018 and 2017, the Company recorded actual forfeitures of $4 million and $8 million respectively, which reduced total stock-based compensation expense. During the year ended December 31, 2016, the Company recorded $5 million of estimated forfeitures.

Future stock-based compensation expense. The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at December 31, 2018:



(in millions)

2019		$	65
2020			34
2021			10
Thereafter			1
	Total	$	110

Disclosures about fair value measurements

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Disclosures about fair value measurements

Note 8. 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 December 31, 2018 and 2017:


		December 31, 2018				December 31, 2017
		Carrying		Fair		Carrying		Fair
(in millions)		Value		Value		Value		Value

Assets:
	Derivative instruments	$	695	$	695	$	-	$	-

Liabilities:
	Derivative instruments	$	-	$	-	$	379	$	379
	Credit facility	$	242	$	242	$	322	$	322
	$600 million 4.375% senior notes due 2025 (a)	$	594	$	591	$	593	$	624
	$1,000 million 3.75% senior notes due 2027 (a)	$	989	$	939	$	987	$	1,012
	$1,000 million 4.3% senior notes due 2028 (a)	$	988	$	980	$	-	$	-
	$800 million 4.875% senior notes due 2047 (a)	$	789	$	761	$	789	$	874
	$600 million 4.85% senior notes due 2048 (a)	$	592	$	573	$	-	$	-


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

Credit facility. The carrying amount of the Company’s amended and restated credit facility (“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 December 31, 2018 and 2017. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.


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


December 31, 2017
				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		$	-	$	13	$	-	$	13	$	(13)	$	-
		Noncurrent:
			Commodity derivatives			-		1		-		1		(1)		-

	Liabilities
		Current:
			Commodity derivatives			-		(290)		-		(290)		13		(277)
		Noncurrent:
			Commodity derivatives			-		(103)		-		(103)		1		(102)

	Net derivative instruments				$	-	$	(379)	$	-	$	(379)	$	-	$	(379)

Concentrations of credit risk. At December 31, 2018, 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. See Note 13 for information regarding the Company’s major customers and derivative counterparties.

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 9 for additional information regarding the Company’s derivative activities.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

Impairments of long-lived assets – The Company periodically reviews its long-lived assets to be held and used, including proved oil and natural gas properties and their integrated assets, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. The Company reviews its oil and natural gas properties by depletion base. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of the Company’s assets, it recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.

The Company calculates the expected undiscounted future net cash flows of its long-lived assets and their integrated assets using management’s assumptions and expectations of (i) commodity prices, which are based on the NYMEX strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, and (vii) prevailing market rates of income and expenses from integrated assets. At December 31, 2018, the Company’s estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a 2019 price of $47.09 per barrel of oil increasing to a 2025 price of $53.10 per barrel of oil. Natural gas prices ranged from a 2019 price of $2.78 per Mcf of natural gas decreasing to a 2021 price of $2.61 per Mcf then rising to a 2025 price of $2.90 per Mcf of natural gas. Both oil and natural gas commodity prices for this purpose were held flat after 2025. The Company did not recognize any impairment loss during the years ended December 31, 2018 or 2017.

The Company calculates the estimated fair values of its long-lived assets and their integrated assets using a discounted future cash flow model. Fair value assumptions associated with the calculation of discounted future net cash flows include (i) market estimates of commodity prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, (vii) prevailing market rates of income and expenses from integrated assets and (viii) discount rate. The expected future net cash flows are discounted using an annual rate of 10 percent to determine fair value. These are classified as Level 3 fair value assumptions.

During the three months ended March 31, 2016, NYMEX strip prices declined as compared to December 31, 2015, and as a result the carrying amount of the Company’s Yeso field of approximately $3.4 billion exceeded the expected undiscounted future net cash flows resulting in a non-cash charge against earnings of approximately $1.5 billion. The non-cash charge represented the amount by which the carrying amount exceeded the estimated fair value of the assets.

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

Derivative financial instruments

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative financial instruments

Note 9. 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’s derivative financial instruments have historically consisted of oil and natural gas swaps and oil basis swaps. Swap contracts allow the Company to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. Basis swap contracts allow the Company to receive a fixed price differential between market indices for the price of oil.

In connection with the RSP Acquisition, the Company assumed certain oil collar and three-way collar contracts. In these contracts, each collar has an established floor price and ceiling price, and certain collars also include a short put price (three-way collars). When the settlement price is below the established floor price, the Company receives an amount from its counterparty equal to the difference between the settlement price and the floor price multiplied by the hedged contract volume. When the settlement price is above the established ceiling price, the Company pays its counterparty an amount equal to the difference between the settlement price and the ceiling price multiplied by the hedged contract volume. When the settlement price is between the established floor and the ceiling, no amounts are due to or from the counterparty. In case of a three-way collar, when the settlement price is below the short put price, the Company receives from its counterparty an amount equal to the difference of the floor price and the short put price multiplied by the hedged contract volume.

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 years ended December 31, 2018, 2017 and 2016:


			Years Ended December 31,
(in millions)				2018		2017		2016

Gain (loss) on derivatives:
	Oil derivatives		$	848	$	(172)	$	(337)
	Natural gas derivatives			(16)		46		(32)
		Total	$	832	$	(126)	$	(369)



The following table represents the Company’s net cash receipts from (payments on) derivatives for the years ended December 31, 2018, 2017 and 2016:



			Years Ended December 31,
(in millions)				2018		2017		2016

Net cash receipts from (payments on) derivatives:
	Oil derivatives		$	(213)	$	79	$	609
	Natural gas derivatives			(5)		-		16
		Total	$	(218)	$	79	$	625

Commodity derivative contracts at December 31, 2018. The following table sets forth the Company’s outstanding derivative contracts at December 31, 2018. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at December 31, 2018 are expected to settle by December 31, 2021.


				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Price Swaps: (a)
	2019:
		Volume (Bbl)		12,352,250		11,199,750		10,434,000		9,852,000		43,838,000
		Price per Bbl	$	56.75	$	56.36	$	56.20	$	56.08	$	56.37
	2020:
		Volume (Bbl)		7,408,500		7,072,500		6,693,000		6,458,000		27,632,000
		Price per Bbl	$	58.38	$	58.37	$	58.24	$	58.22	$	58.31
Oil Costless Collars: (a)
	2019:
		Volume (Bbl)		1,335,250		1,213,250		1,135,000		1,058,000		4,741,500
		Ceiling price per Bbl	$	64.67	$	64.00	$	63.47	$	62.95	$	63.83
		Floor price per Bbl	$	56.46	$	56.06	$	55.74	$	55.43	$	55.96
Oil Basis Swaps: (b)
	2019:
		Volume (Bbl)		11,693,000		11,601,500		11,178,000		10,717,000		45,189,500
		Price per Bbl	$	(3.00)	$	(3.04)	$	(2.99)	$	(3.10)	$	(3.03)
	2020:
		Volume (Bbl)		8,645,000		8,645,000		8,740,000		8,740,000		34,770,000
		Price per Bbl	$	(0.82)	$	(0.82)	$	(0.82)	$	(0.82)	$	(0.82)
	2021:
		Volume (Bbl)		1,350,000		1,365,000		1,380,000		1,380,000		5,475,000
		Price per Bbl	$	0.59	$	0.59	$	0.59	$	0.59	$	0.59
Natural Gas Price Swaps: (c)
	2019:
		Volume (MMBtu)		10,891,533		17,241,387		17,298,537		17,209,535		62,640,992
		Price per MMBtu	$	2.86	$	2.87	$	2.87	$	2.87	$	2.87
	2020:
		Volume (MMBtu)		4,413,500		4,413,500		4,278,000		4,278,000		17,383,000
		Price per MMBtu	$	2.70	$	2.70	$	2.70	$	2.70	$	2.70


(a) The oil derivative contracts are settled based on the NYMEX – WTI monthly 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 connection with 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. In September 2017, the Company elected to enter into an “Investment Grade Period,” as defined in Note 10, under the Credit Facility, which had the effect of releasing all collateral formerly securing the Credit Facility. Additionally, as a result of the Company’s Investment Grade Period election along with amendments to certain ISDA Agreements with the Company’s derivative counterparties, the Company’s derivatives are no longer secured. See Note 10 for additional information regarding the Credit Facility.

Debt

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Debt

Note 10. Debt

The Company’s debt consisted of the following at December 31, 2018 and 2017:


				December 31,
(in millions)				2018		2017

Credit facility due 2022			$	242	$	322
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		-
4.875% unsecured senior notes due 2047				800		800
4.85% unsecured senior notes due 2048				600		-
Unamortized original issue discount				(10)		(6)
Senior notes issuance costs, net				(38)		(25)
	Less: current portion			-		-
		Total long-term debt	$	4,194	$	2,691


(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.
(a)

Credit Facility. The Credit Facility has a maturity date of May 9, 2022. At December 31, 2018, the Company’s commitments from its bank group were $2.0 billion.

In April 2017, the Company amended the Credit Facility to extend the maturity date and decrease unused lender commitments. The amendment also lowered the corporate ratings floor sufficient to automatically terminate an Investment Grade Period under the Credit Facility from (i) “Ba1” to “Ba2” for Moody’s Investors Service, Inc. (“Moody’s”) and (ii) “BB+” to “BB” for S&P Global Ratings (“S&P”).

The Company recorded a loss on extinguishment of debt of approximately $1 million in 2017 for the proportional amount of unamortized deferred loan costs associated with banks that are no longer in the Credit Facility syndicate as a result of the April 2017 amendment.

In September 2017, the Company elected to enter into an Investment Grade Period under the Credit Facility, which had the effect of releasing all collateral formerly securing the Credit Facility. If the Investment Grade Period under the Credit Facility terminates (whether automatically due to a downgrade of the Company’s credit ratings below certain thresholds or by the Company’s election), the Credit Facility will once again be secured by a first lien on substantially all of the Company’s oil and natural gas properties and by a pledge of the equity interests in its subsidiaries. At December 31, 2018, certain of the Company’s 100 percent owned subsidiaries are guarantors under the Credit Facility.

During an Investment Grade Period, advances on the Credit Facility bear interest, at the Company’s option, based on (i) an alternative base rate, which is equal to the highest of (a) the prime rate of JPMorgan Chase Bank (5.5 percent at December 31, 2018), (b) the federal funds effective rate plus 0.5 percent and (c) LIBOR plus 1.0 percent or (ii) LIBOR. The Credit Facility’s interest rates and commitment fees on the unused portion of the available commitment vary depending on the Company’s credit ratings from Moody’s and S&P. At the Company’s 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. During the years ended December 31, 2018, 2017 and 2016, the Company incurred commitment fees on the unused portion of the available commitments of $5 million, $6 million and $8 million, respectively. The Company had $1.8 billion of unused commitments, net of letters of credit, under the Credit Facility at December 31, 2018.

The Credit Facility contains various restrictive covenants and compliance requirements, which include:

maintenance of certain financial ratios, including maintenance of a quarterly ratio of consolidated total debt to consolidated earnings, as defined, before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and other non-cash income and expenses to be no greater than 4.25 to 1.0, and during an Investment Grade Period, if the Company does not have both a rating of “Baa3” or better from Moody’s and a rating of “BBB-” or better from S&P, maintenance of a quarterly ratio of PV-9 of the Company’s oil and natural gas properties reflected in its most recently delivered reserve report to consolidated total debt to be no less than 1.50 to 1.0;

limits on the incurrence of additional indebtedness and certain types of liens;

restrictions as to mergers, combinations and dispositions of assets; and

restrictions on the payment of cash dividends.

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 17, and rank equally in right of payments with one another.

On July 2, 2018, the Company issued $1,600 million in aggregate principal amount of unsecured senior notes, consisting of $1,000 million in aggregate principal amount of 4.3% unsecured senior notes due 2028 (the “4.3% Notes”) and $600 million in aggregate principal amount of 4.85% unsecured senior notes due 2048 (the “4.85% Notes” and, together with the 4.3% Notes, the “Notes”). The 4.3% Notes were issued at a price equal to 99.660 percent of par, and the 4.85% Notes were issued at a price equal to 99.740 percent of par. The net proceeds of approximately $1,579 million were used to redeem and cancel all of RSP’s outstanding $700 million aggregate principal amount of 6.625% unsecured senior notes due 2022 (the “RSP 2022 Notes”) and $450 million aggregate principal amount of 5.25% unsecured senior notes due 2025 (the “RSP 2025 Notes” and, together with the RSP 2022 Notes, the “RSP Notes”). The Company made aggregate payments of approximately $1.2 billion to redeem and cancel the RSP Notes, including make-whole call premiums of approximately $35 million and $33 million for the RSP 2022 Notes and RSP 2025 Notes, respectively. The Company also paid accrued interest of approximately $14 million on the RSP Notes. The remaining proceeds, along with borrowings under the Credit Facility, were used to repay the $540 million of outstanding principal under RSP’s revolving credit facility, including $1 million in accrued interest. See Note 4 for additional information regarding the RSP Acquisition.

In September 2017, the Company issued $1,800 million in aggregate principal amount of unsecured senior notes, consisting of $1,000 million in aggregate principal amount of 3.75% unsecured senior notes due 2027 (the “3.75% Notes”) and $800 million in aggregate principal amount of 4.875% unsecured senior notes due 2047 (the “4.875% Notes” and, together with the 3.75% Notes, the “2017 Notes”). The 3.75% Notes were issued at a price equal to 99.636 percent of par, and the 4.875% Notes were issued at a price equal to 99.749 percent of par. The Company received net proceeds of approximately $1,777 million.

Additionally, in September 2017, the Company completed a cash tender offer (the “Tender Offer”) to purchase any and all of the outstanding $600 million aggregate principal amount of its 5.5% unsecured senior notes due 2022 and the outstanding $1,550 million aggregate principal amount of its 5.5% unsecured senior notes due 2023 (collectively, the “5.5% Notes”). The Company received tenders from the holders of approximately $1,232 million in aggregate principal amount, or approximately 57.3 percent, of its outstanding 5.5% Notes in connection with the Tender Offer at a price of 102.934 percent of the unpaid principal amount plus accrued and unpaid interest to the settlement date.

In connection with the Tender Offer, the Company redeemed the remaining outstanding 5.5% Notes not purchased in the Tender Offer at a price, including the make-whole premium as determined in accordance with the indentures, of 102.75 percent of the unpaid principal amount plus accrued and unpaid interest. Additionally in September 2017, the Company completed a satisfaction and discharge of the redeemed notes, where the Company prepaid interest to October 13, 2017. The Company used the net proceeds from the offering of the 2017 Notes, together with cash on hand and borrowings under its Credit Facility, to fund the Tender Offer and the satisfaction and discharge of its obligations under the indentures of the 5.5% Notes.

As a result of these transactions, the Company recorded a loss on extinguishment of debt for the year ended December 31, 2017 as follows:


			Senior Notes
			September 2017
(in millions)			Tender Offer		Extinguishment		Total

Cash:
	Tender premium		$	36	$	-	$	36
	Make-whole premium			-		25		25
	Prepaid interest			-		2		2
		Total cash		36		27		63
Non-cash:
	Unamortized original issue premium			(11)		(8)		(19)
	Unamortized deferred loan costs			12		9		21
		Total non-cash		1		1		2
Total loss on extinguishment of debt			$	37	$	28	$	65

In December 2016, the Company issued $600 million in aggregate principal amount of 4.375% senior notes due 2025 at par, for which it received net proceeds of approximately $593 million. The Company used the net proceeds from the offering to fund the satisfaction and discharge of its obligations under the indenture of the $600 million outstanding principal amount of its 6.5% unsecured senior notes due 2022 (the “6.5% Notes”) at a price equal to 103.25 percent of par. The early extinguishment price included the make-whole premium as determined in accordance with the indenture governing the 6.5% Notes. In December 2016, the Company also paid interest of approximately $20 million on the 6.5% Notes through January 16, 2017.

The Company recorded a loss on extinguishment of debt related to the 6.5% Notes of approximately $28 million for the year ended December 31, 2016. This amount includes $20 million associated with the make-whole premium paid for the early extinguishment of the notes, approximately $7 million of unamortized deferred loan costs and approximately $1 million of additional interest on the 6.5% Notes through January 16, 2017, which was paid in December 2016.

In September 2016, the Company redeemed the $600 million outstanding principal amount of its 7.0% unsecured senior notes due 2021 (the “7.0% Notes”) at a price equal to 103.5 percent of par. The redemption price included the make-whole premium for the early redemption, as determined in accordance with the indenture governing the 7.0% Notes. The Company also paid accrued and unpaid interest on the 7.0% Notes through September 19, 2016, the redemption date.

The Company recorded a loss on extinguishment of debt related to the redemption of the 7.0% Notes of approximately $28 million for the year ended December 31, 2016. This amount includes $21 million associated with the make-whole premium paid for the early redemption of the notes and approximately $7 million of unamortized deferred loan costs.

At December 31, 2018, the Company was in compliance with the covenants under all of its debt instruments.

Principal maturities of long-term debt. Principal maturities of long-term debt outstanding at December 31, 2018 were as follows:


(in millions)

2019		$	-
2020			-
2021			-
2022			242
2023			-
Thereafter			4,000
	Total	$	4,242

Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2018, 2017 and 2016:


		Years Ended December 31,
(in millions)			2018		2017		2016

Cash payments for interest		$	118	$	139	$	232
Non-cash interest			5		6		9
Net changes in accruals			34		4		(37)
	Interest costs incurred		157		149		204
Less: capitalized interest			(8)		(3)		-
	Total interest expense	$	149	$	146	$	204

Commitments and contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and contingencies

Note 11. Commitments and contingencies

Severance agreements. The Company has entered into severance and change in control agreements with all of its officers. The current annual salaries for the Company’s officers covered under such agreements total approximately $9 million.

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

Legal actions. The Company is a party to proceedings and claims incidental to its business. 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.

Regulatory and environmental compliance. Regulatory liabilities relate to acquisitions where additional equipment is necessary to have facilities compliant with local, state and federal obligations. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs. At December 31, 2018 and 2017, the Company had regulatory and environmental liabilities of approximately $26 million and $3 million, respectively, which are included in other current liabilities on the accompanying consolidated balance sheets. During the years ended December 31, 2018, 2017 and 2016, the Company recognized regulatory and environmental charges of approximately $23 million, $9 million and $7 million, respectively, which are included in oil and natural gas production expense in the accompanying consolidated statements of operations.

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 drilling commitments, water commitment agreements, throughput volume delivery commitments, fixed and variable power commitments, sand commitment agreements, fixed asset commitments and maintenance commitments. The following table summarizes the Company’s commitments at December 31, 2018:

							Drilling
			Volume Delivery		Power		Commitments
(in millions)			Commitments		Commitments (a)		and Other		Total

2019		$	12	$	11	$	65	$	88
2020			28		13		38		79
2021			29		12		35		76
2022			21		12		3		36
2023			19		12		2		33
Thereafter			73		50		7		130
	Total	$	182	$	110	$	150	$	442


(a)	Certain power commitments include a variable price component that is based on the last day settlement price of the NYMEX futures contract for the physical delivery period.
(a)

At December 31, 2018, the Company’s delivery commitments covered the following gross volumes of oil and natural gas:

		Oil	Natural Gas
		(in MMBbl)	(in MMcf)

2019		19	5,148
2020		38	17,321
2021		39	21,627
2022		41	16,425
2023		33	16,425
Thereafter		147	49,320
	Total	317	126,266

Throughput sales commitment. 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.

Operating leases. Lease payments associated with operating leases for the year ended December 31, 2018 were approximately $13 million, $10 million and $8 million for the years ended December 31, 2017 and 2016, respectively.

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

Income taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income taxes

Note 12. Income taxes

The Company uses an asset and liability approach for financial accounting and reporting for income taxes. The Company’s objectives of accounting for income taxes are to recognize (i) the amount of taxes payable or refundable for the current year and (ii) deferred tax liabilities and assets for the future tax consequences of events that have been recognized in its financial statements or tax returns. The Company and its subsidiaries file a federal corporate income tax return on a consolidated basis. The tax returns and the amount of taxable income or loss are subject to examination by federal and state taxing authorities.

The Company’s income tax expense (benefit) attributable to income (loss) from operations consisted of the following for the years ended December 31, 2018, 2017 and 2016:


				Years Ended December 31,
(in millions)					2018		2017		2016

Current:
	U.S. federal			$	-	$	(6)	$	(12)
	U.S. state and local				(2)		2		-
		Total current income tax benefit			(2)		(4)		(12)
Deferred:
	U.S. federal				547		(94)		(771)
	U.S. state and local				58		23		(93)
		Total deferred income tax expense (benefit)			605		(71)		(864)
			Total income tax expense (benefit)	$	603	$	(75)	$	(876)

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


		Years Ended December 31,
(in millions)			2018		2017		2016

Income (loss) at U.S. federal statutory rate		$	607	$	308	$	(818)
Enactment date and measurement period adjustments from the TCJA			(7)		(398)		-
State income taxes, net of federal tax effect			52		17		(41)
Change in estimated effective statutory state income tax rate			(8)		-		(21)
Excess tax benefit due to stock-based compensation			(12)		(6)		-
Research and development credits, net of unrecognized tax benefits			(41)		-		-
Other			12		4		4
	Income tax expense (benefit)	$	603	$	(75)	$	(876)

Effective tax rate			21%		(9)%		38%

On December 22, 2017, the President signed into law the TCJA, which enacted significant changes to federal income tax laws, including a decrease in the federal corporate income tax rate from 35 percent to 21 percent, which was effective January 1, 2018. In accordance with SAB 118, the Company recorded, based on reasonable estimates, a $398 million decrease to its income tax provision at December 31, 2017. This provisional amount related to the re-measurement of certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future. At December 31, 2018, the Company completed its accounting for all of the enactment-date tax effects of the TCJA and recognized an adjustment of $7 million which is included as a component of income tax expense.

The Company monitors changes in enacted tax rates for the jurisdictions in which it operates. The Company monitors its state tax apportionment footprint and makes updates for changes in its projected activity, including changes in budgets and drilling plans and changes as a result of acquisitions or divestitures. Based upon the Company’s projected future activity for the states in which it conducts business, the timing for when it anticipates its deferred tax items to become taxable and enacted tax rates at such time deferred items become taxable, the Company revised its estimated state tax rate, primarily due to the impact of the RSP Acquisition. As a result, the Company recorded an income tax benefit of approximately $8 million, net of federal tax benefit, in its income tax provision for the year ended December 31, 2018. The Company did not revise its estimated state rate and, as such, did not record an additional deferred state tax benefit for the year ended December 31, 2017. The Company revised its estimated state rate and recorded a deferred state tax benefit of approximately $21 million for the year ended December 31, 2016.

The Company recorded an income tax benefit of approximately $12 million and $6 million for the years ended December 31, 2018 and 2017, respectively, related to excess tax benefits on stock-based awards, which are recorded in the income tax provision pursuant to ASU 2016-09 adopted on January 1, 2017.

At December 31, 2018, the Company had approximately $2.2 billion of federal net operating losses (“NOLs”), including $516 million acquired from RSP, net of reduction for unrecognized tax benefits. At December 31, 2018, the Company had approximately $1.5 billion of NOLs that will begin to expire in the tax year 2034 but are allowable as a deduction against 100 percent of future taxable income since they were generated prior to the effective date of the limitations imposed by the TCJA. Additionally, the Company has estimated an apportioned New Mexico NOL of approximately $520 million that will begin to expire in 2036.

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows:


					December 31,
(in millions)					2018			2017

Deferred tax assets:
	Stock-based compensation				$	26	$	18
	Derivative instruments					-		87
	Asset retirement obligation					41		33
	Net operating losses and other carryforwards					525		31
	Research and development and other credits					61		-
	Other					17		13
		Total deferred tax assets				670		182
			Less: Valuation allowance			(3)		-
				Net deferred tax assets		667		182

Deferred tax liabilities:
	Oil and natural gas properties, principally due to differences in basis and
		depreciation and the deduction of intangible drilling costs for tax purposes				(2,270)		(852)
	Intangible assets - operating rights					(4)		(5)
	Derivative instruments					(158)		-
	Other					(43)		(12)
		Total deferred tax liabilities				(2,475)		(869)
				Net deferred tax liabilities	$	(1,808)	$	(687)

On July 19, 2018, the Company completed the RSP Acquisition. For federal income tax purposes, the transaction qualified as a tax-free merger whereby the Company acquired carryover tax basis in RSP’s assets and liabilities. As of December 31, 2018, the Company recorded an opening balance sheet deferred tax liability of $515 million, which includes a deferred tax asset related to tax attributes acquired from RSP. The acquired income tax attributes primarily consist of NOLs and research and development credits that are subject to an annual limitation under Internal Revenue Code Section 382. The Company expects that these tax attributes will be fully utilized prior to expiration. The Company had net deferred tax liabilities of approximately $1.8 billion and $687 million as of December 31, 2018 and 2017, respectively.

Pursuant to management’s assessment, the Company does not believe a cumulative ownership change has occurred as of December 31, 2018. As such, Section 382 of the Internal Revenue Code of 1986, as amended, is not expected to limit the Company’s ability to utilize its NOL carryforward as of December 31, 2018. As noted above, tax attributes acquired from RSP include NOLs and credits subject to an annual limitation under Section 382; however, the Company expects that these tax attributes will be fully utilized prior to expiration.

Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s NOLs and other deferred tax attributes will be utilized prior to their expiration. At December 31, 2018, management considered all factors including the expected reversal of deferred tax liabilities (including the impact of available carryforward periods), historical operating income tax planning strategies and projected future taxable income. Based on the results of the assessment, a valuation allowance of $3 million was recorded related to charitable contribution carryforwards not anticipated to be utilized prior to expiration. Management determined that it is more likely than not that the Company will realize its remaining deferred tax assets.

The following table sets forth changes in the Company’s unrecognized tax benefits:


		December 31,
(in millions)		2018

Balance at beginning of year		$	-
	Increase resulting from tax positions acquired		26
	Increase resulting from prior period tax positions		20
	Increase resulting from current tax period positions		26
Balance at end of year			72
	Less: Effects of temporary items		(9)
Total that, if recognized, would impact the effective income tax as of the end of the year		$	63

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 unrecognized tax benefits of approximately $63 million, primarily related to research and development credits. 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, but the Company does not expect that a change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

The Company has not recognized any interest or penalties relating to unrecognized tax benefits in its consolidated financial statements. Any interest or penalties would be recognized as a component of income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2013.

Major customers and derivative counterparties

12 Months Ended

Dec. 31, 2018

Major Customer Disclosure [Abstract]

Major Customers and Derivative Counterparties [Text Block]

Note 13. Major customers and derivative counterparties

Sales to major customers. The Company’s share of oil and natural gas production is sold to various purchasers. The Company is of the opinion that the loss of any one purchaser would not have a material adverse effect on the ability of the Company to sell its oil and natural gas production.

The following purchasers individually accounted for 10 percent or more of the consolidated oil and natural gas revenues during the years ended December 31, 2018, 2017 and 2016:


	Years Ended December 31,
	2018	2017	2016

Plains Marketing and Transportation, Inc.	18%	21%	29%
Holly Frontier Refining and Marketing, LLC	(a)	10%	16%

(a) This purchaser did not account for 10% or more of total revenue for the period.

At December 31, 2018, the Company had receivables from Plains Marketing & Transportation Inc. of $82 million, which are reflected in accounts receivable — oil and natural gas in the accompanying consolidated balance sheets.

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.

At December 31, 2018, the Company had a net asset position of $695 million as a result of outstanding derivative contracts which are reflected in the accompanying consolidated balance sheets. The Company assessed the balances held by each of its derivative counterparties for concentration risk and noted balances of approximately $151 million, $92 million and $84 million with JP Morgan, Citigroup and Wells Fargo, respectively.

Related party transactions	12 Months Ended
Related party transactions	Dec. 31, 2018
Related Party Transactions [Abstract]
Related party transactions	Note 14. 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. These payments were reported in the Company’s consolidated statements of operations and totaled approximately $8 million, $7 million and $4 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Earnings per share

12 Months Ended

Dec. 31, 2018

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

Earnings per share

Note 15. 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 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 per share attributable to common stockholders is computed as (i) basic earnings 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 from operations and earnings attributable to common stockholders to the basic and diluted earnings used to determine the Company’s earnings per share amounts for the years ended December 31, 2018, 2017 and 2016, respectively, under the two-class method:


			Years Ended December 31,
(in millions, except per share amounts)			2018		2017		2016

Net income (loss) as reported			$	2,286	$	956	$	(1,462)
Participating basic earnings (a)				(17)		(7)		-
	Basic earnings attributable to common stockholders			2,269		949		(1,462)
Reallocation of participating earnings				-		-		-
	Diluted earnings attributable to common stockholders		$	2,269	$	949	$	(1,462)


(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 earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so.

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2018, 2017 and 2016:


			Years Ended December 31,
(in thousands)			2018	2017	2016

Weighted average common shares outstanding:
	Basic		170,925	147,320	134,755
		Dilutive common stock options	-	3	-
		Dilutive performance units	324	633	-
	Diluted		171,249	147,956	134,755

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


		Years Ended December 31,
(in thousands)		2018	2017	2016

Number of antidilutive common shares:
	Antidilutive performance units	108	81	-

Other current liabilities

12 Months Ended

Dec. 31, 2018

Other Liabilities Disclosure [Abstract]

Other current liabilities

Note 16. Other current liabilities

The following table provides the components of the Company’s other current liabilities at December 31, 2018 and 2017:


				December 31,
(in millions)				2018		2017

Other current liabilities:
	Accrued production costs		$	135	$	72
	Payroll related matters			49		40
	Accrued interest			70		36
	Settlements due on derivatives			-		25
	Asset retirement obligations			11		12
	Other			55		31
		Other current liabilities	$	320	$	216

Subsidiary guarantors

12 Months Ended

Dec. 31, 2018

Guarantees [Abstract]

Subsidiary guarantors

Note 17. Subsidiary guarantors

At December 31, 2018, 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 10 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 “Subsidiary Non-Guarantors” in the tables below. An additional entity did not guarantee the Company’s senior notes at December 31, 2017. This entity was a VIE that was formed to effectuate a tax-free exchange of assets. During 2018, the Reverse Exchange 1031 was completed and all assets and liabilities attributable to the VIE were conveyed to the Company. This entity did not guarantee the Company’s senior notes until the conveyance was completed. See Note 5 for additional information regarding the completion of the Reverse 1031 Exchange. 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 December 31, 2018 and 2017, condensed consolidating statements of operations and condensed consolidating statements of cash flows for the years ended December 31, 2018, 2017 and 2016, 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
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 Balance Sheet
December 31, 2017

			Parent	Subsidiary		Subsidiary			Consolidating
(in millions)			Issuer	Guarantors		Non-Guarantors			Entries		Total

ASSETS
Accounts receivable - related parties		$	8,836	$	(669)	$	-	$	(8,167)	$	-
Other current assets			6		576		10		-		592
Oil and natural gas properties, net			-		12,192		615		-		12,807
Property and equipment, net			-		234		-		-		234
Investment in subsidiaries			3,202		-		-		(3,202)		-
Other long-term assets			23		76		-		-		99
	Total assets	$	12,067	$	12,409	$	625	$	(11,369)	$	13,732

LIABILITIES AND EQUITY
Accounts payable - related parties		$	(669)	$	8,223	$	613	$	(8,167)	$	-
Other current liabilities			341		821		3		-		1,165
Long-term debt			2,691		-		-		-		2,691
Other long-term liabilities			789		166		6		-		961
Equity			8,915		3,199		3		(3,202)		8,915
	Total liabilities and equity	$	12,067	$	12,409	$	625	$	(11,369)	$	13,732

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2018

		Parent		Subsidiary		Subsidiary		Consolidating
(in millions)		Issuer		Guarantors		Non-Guarantor		Entries		Total
Total operating revenues		$	-	$	4,146	$	5	$	-	$	4,151
Total operating costs and expenses			829		(2,047)		(3)		-		(1,221)
	Income from operations		829		2,099		2		-		2,930
Interest expense			(149)		-		-		-		(149)
Other, net			2,209		108		-		(2,209)		108
	Income before income taxes		2,889		2,207		2		(2,209)		2,889
Income tax expense			(603)		-		-		-		(603)
	Net income	$	2,286	$	2,207	$	2	$	(2,209)	$	2,286

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2017


		Parent		Subsidiary		Subsidiary		Consolidating
(in millions)		Issuer		Guarantors		Non-Guarantors		Entries		Total

Total operating revenues		$	-	$	2,566	$	20	$	-	$	2,586
Total operating costs and expenses			(129)		(1,369)		(17)		-		(1,515)
	Income (loss) from operations		(129)		1,197		3		-		1,071
Interest expense			(145)		(1)		-		-		(146)
Loss on extinguishment of debt			(66)		-		-		-		(66)
Other, net			1,221		22		-		(1,221)		22
	Income before income taxes		881		1,218		3		(1,221)		881
Income tax benefit			75		-		-		-		75
	Net income	$	956	$	1,218	$	3	$	(1,221)	$	956

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2016

			Parent		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Entries		Total

Total operating revenues		$	-	$	1,635	$	-	$	1,635
Total operating costs and expenses			(370)		(3,339)		-		(3,709)
	Loss from operations		(370)		(1,704)		-		(2,074)
Interest expense			(202)		(2)		-		(204)
Loss on extinguishment of debt			(56)		-		-		(56)
Other, net			(1,710)		(4)		1,710		(4)
	Loss before income taxes		(2,338)		(1,710)		1,710		(2,338)
Income tax benefit			876		-		-		876
	Net loss	$	(1,462)	$	(1,710)	$	1,710	$	(1,462)

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2018

			Parent	Subsidiary		Subsidiary			Consolidating
(in millions)			Issuer	Guarantors		Non-Guarantor			Entries			Total

Net cash flows provided by operating activities		$	338	$	2,220		$	-	$	-	$	2,558
Net cash flows used in investing activities			-		(2,216)			-		-		(2,216)
Net cash flows used in financing activities			(338)		(4)			-		-		(342)
	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
For the Year Ended December 31, 2017

			Parent	Subsidiary		Subsidiary			Consolidating
(in millions)			Issuer	Guarantors		Non-Guarantors			Entries			Total

Net cash flows provided by operating activities		$	145	$	1,549		$	1	$	-	$	1,695
Net cash flows used in investing activities			-		(1,105)			(614)		-		(1,719)
Net cash flows provided by (used in) financing
	activities		(145)		(497)			613		-		(29)
	Net decrease in cash and cash equivalents		-		(53)			-		-		(53)
	Cash and cash equivalents at beginning of period		-		53			-		-		53
	Cash and cash equivalents at end of period	$	-	$	-		$	-	$	-	$	-

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2016

			Parent		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Entries		Total

Net cash flows provided by (used in) operating activities		$	(665)	$	2,049	$	-	$	1,384
Net cash flows used in investing activities			-		(2,225)		-		(2,225)
Net cash flows provided by financing activities			665		-		-		665
	Net decrease in cash and cash equivalents		-		(176)		-		(176)
	Cash and cash equivalents at beginning of period		-		229		-		229
	Cash and cash equivalents at end of period	$	-	$	53	$	-	$	53

Subsequent events

12 Months Ended

Dec. 31, 2018

Subsequent Events [Abstract]

Subsequent events

Note 18. Subsequent events

Dividends. On February 19, 2019, the Company’s board of directors declared a cash dividend of $0.125 per share for the first quarter of 2019. The total cash dividend, including the cash dividend on unvested restricted stock awards, of $25 million is expected to be paid on March 29, 2019. Any payment of future dividends will be at the discretion of the Company’s board of directors and will depend on, among other things, the Company’s earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the Company’s board of directors deems relevant. Covenants contained in the Company’s agreement governing its Credit Facility and the indentures governing the Company’s senior notes could limit the payment of dividends.

Marketing contract. Consistent with the Company’s strategy of diversifying its oil pricing, in January 2019, the Company entered into a firm sales agreement with a third-party purchaser. The purchaser provides an integrated transportation and marketing strategy, including ample dock capacity. 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.

New commodity derivative contracts. After December 31, 2018, 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)		1,357,000		2,184,000		1,564,000		1,380,000		6,485,000
		Price per Bbl	$	54.75	$	54.92	$	54.51	$	54.41	$	54.68
	2020:
		Volume (Bbl)		3,094,000		3,094,000		2,760,000		2,760,000		11,708,000
		Price per Bbl	$	54.65	$	54.65	$	54.61	$	54.61	$	54.63
	2021:
		Volume (Bbl)		2,070,000		2,093,000		1,932,000		1,932,000		8,027,000
		Price per Bbl	$	54.50	$	54.50	$	54.42	$	54.42	$	54.46
Oil Basis Swaps: (b)
	2019:
		Volume (Bbl)		236,000		364,000		1,472,000		1,472,000		3,544,000
		Price per Bbl	$	(2.80)	$	(2.80)	$	(1.51)	$	(1.51)	$	(1.73)
	2020:
		Volume (Bbl)		2,002,000		1,547,000		1,380,000		1,380,000		6,309,000
		Price per Bbl	$	(0.11)	$	(0.01)	$	0.01	$	0.01	$	(0.03)
	2021:
		Volume (Bbl)		720,000		728,000		736,000		736,000		2,920,000
		Price per Bbl	$	0.48	$	0.48	$	0.48	$	0.48	$	0.48
Natural Gas Price Swaps: (c)
	2020:
		Volume (MMBtu)		1,820,000		1,820,000		1,840,000		1,840,000		7,320,000
		Price per MMBtu	$	2.70	$	2.70	$	2.70	$	2.70	$	2.70


(a)		The oil derivative contracts are settled based on the NYMEX – WTI monthly average futures price.
(b)		The basis differential price is between Midland – WTI and Cushing – WTI.
(c)		The natural gas derivative contracts are settled based on the NYMEX – Henry Hub last trading day futures price.

Summary of significant accounting policies (Policies)

12 Months Ended

Dec. 31, 2018

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 consolidated financial statements also included the accounts of a variable interest entity (“VIE”) where the Company was the primary beneficiary of the arrangements until the VIE structure dissolved in January 2018. See Note 5 for additional information regarding the circumstances surrounding the VIE. 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 2018 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 GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, 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.

Cash equivalents

Cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

Accounts receivable

Accounts receivable. The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Oil and natural gas sales receivables related to these operations are generally unsecured. Joint interest receivables are generally secured pursuant to the operating agreement between or among the co-owners of the operated property. The Company determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and the Company’s ability to realize the receivables through netting of anticipated future production revenues. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The Company had an allowance for doubtful accounts of approximately $5 million and $1 million for the years ended December 31, 2018 and 2017, respectively.

Inventory

Inventory. Inventory consists primarily of tubular goods, water and other oilfield equipment that the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of weighted average cost or net realizable value

Oil and natural gas properties

Oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized leasehold costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized drilling and development costs and integrated assets is based on the unit-of-production method using proved developed reserves. The Company recognized depletion expense of $1.5 billion, $1.1 billion and $1.1 billion during the years ended December 31, 2018, 2017 and 2016, respectively.

The Company generally does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:

the well has found a sufficient quantity of reserves to justify its completion as a producing well; and
the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the Company’s large multi-well project development program, capital intensive nature and geographical location of certain projects, it may take longer than one year to evaluate the future potential of the exploration well and economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. The Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves and is transferred to proved oil and natural gas properties or is noncommercial and is charged to exploration and abandonments expense. See Note 3 for additional information regarding the Company’s exploratory well costs.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire depletion base is sold. However, gain or loss is recognized from the sale of less than an entire depletion base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. Ordinary maintenance and repair costs are expensed as incurred.

Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed. The Company capitalizes interest on expenditures for significant development projects until such projects are ready for their intended use. During the years ended December 31, 2018 and 2017, the Company had capitalized interest of approximately $9 million and $3 million, respectively. The Company did not have capitalized interest related to significant oil and natural gas development projects for the year ended December 31, 2016.

The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by depletion base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties and integrated assets would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs and cash flows from integrated assets. The Company did not recognize impairment expense during the years ended December 31, 2018 and 2017. The Company recognized impairment expense of approximately $1.5 billion during the year ended December 31, 2016 related to its proved oil and natural gas properties. See Note 8 for additional information regarding the Company’s impairment expense.

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects. During the years ended December 31, 2018, 2017 and 2016, the Company recognized expense of approximately $35 million, $27 million and $50 million, respectively, related to abandoned and expiring acreage, which is included in exploration and abandonments expense in the accompanying consolidated statements of operations.

Other property and equipment

Other property and equipment. Other capital assets include buildings, transportation equipment, computer equipment and software, telecommunications equipment, leasehold improvements and furniture and fixtures. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two to 39 years. The Company had other capital assets of $308 million and $234 million, net of accumulated depreciation of $109 million and $90 million, at December 31, 2018 and December 31, 2017, respectively. During the years ended December 31, 2018, 2017 and 2016, the Company recognized depreciation expense of $22 million, $21 million and $21 million, respectively.

Goodwill

Goodwill. As a result of the RSP Acquisition, as defined in Note 4, the Company has goodwill in the amount of $2.2 billion at December 31, 2018. Goodwill is not amortized but assessed for impairment on an annual basis, or more frequently if indicators of impairment exist. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed as of July 1 of each year. The balance of goodwill is allocated in its entirety to the Company’s one reporting unit. When testing goodwill for impairment, the Company first performs a qualitative analysis to determine if it is more likely than not that the fair value of its reporting unit is less than its carrying value. If the analysis shows that the fair value is more likely than not less than the carrying value, then the Company performs a quantitative impairment test. The Company early adopted Accounting Standards Update (“ASU”) No. 2017-04, “Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (“ASU 2017-04”). Per ASU 2017-04, if the results of the quantitative test are such that the fair value of the reporting unit is less than the carrying value, goodwill is reduced by an amount that is equal to the amount by which the carrying value of the reporting unit exceeds the fair value. Because of the recent decline in the price of oil and the volatility of the Company’s common stock, the Company performed an analysis at December 31, 2018 and determined that it was not more likely than not that the fair value of its reporting unit was less than its carrying value. As a result, the Company did not recognize impairment expense during the year ended December 31, 2018.

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 December 31, 2018, 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 and approximately $49 million at December 31, 2018 and 2017, respectively. The Company recorded income of approximately $4 million and $7 million for the years ended December 31, 2018 and 2017, respectively. The Company will not record income or loss on the Oryx investment until such net income is greater than the distribution in excess of its investment.

On December 26, 2018, the Company contributed certain infrastructure assets to WaterBridge Operating LLC (“WaterBridge”), an entity that operates and manages various water infrastructure assets located in the Permian Basin, in exchange for, among other consideration, 100,000 Series A-1 Preferred Units (“Preferred Units”). The Preferred Units contain certain redemption rights, incentives and restrictions, as specified in the agreement. The Company accounts for the investment using the equity method. In conjunction with the transaction, the Company entered into a water management services agreement with WaterBridge. The Company had no amounts due to WaterBridge at December 31, 2018. The Company’s investment in WaterBridge is recorded in other assets in the Company’s consolidated balance sheets.

In February 2017, the Company closed on the divestiture of its 50 percent membership interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), that constructed a crude oil gathering and transportation system in the Delaware Basin. See Note 5 for additional information regarding the disposition of ACC.

Regulatory and environmental compliance

Regulatory and environmental compliance. The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Regulatory liabilities relate to acquisitions where additional equipment is necessary to have facilities compliant with local, state and federal obligations and are capitalized. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures that are noncapital in nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Environmental liabilities normally involve estimates that are subject to revisions until settlement occurs. See Note 11 for additional information.

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 11 for additional information.

Income taxes

Income taxes. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

On December 22, 2017, the President of the United States (the “President”) signed into law the tax bill commonly referred to as the “Tax Cuts and Job Act” (“TCJA”), significantly changing federal income tax laws. According to the Accounting Standards Codification (“ASC”) section 740, “Income Taxes,” (“ASC 740”), a company is required to record the effects of an enacted tax law or rate change in the period of enactment, which is the date the bill is signed by the President and becomes law. As a result of the enactment of the TCJA, the U.S. Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” (“SAB 118”) to provide guidance for companies that have not completed the accounting for the income tax effects of the TCJA in the period of enactment. SAB 118 allowed companies to report provisional amounts when based on reasonable estimates and to adjust these amounts during a measurement period of up to one year. The Company elected to apply SAB 118 and, as such, recorded provisional amounts for the income tax balances reported in its consolidated financial statements at December 31, 2017. At December 31, 2018, the Company completed its accounting for all tax effects of the TCJA and made an adjustment to its provisional amounts related to the deductibility of certain compensation based on available regulatory and interpretive guidance. See Note 12 for additional information regarding the Company’s deferred tax balances and the impacts of the TCJA.

Income taxes uncertainties

The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. At December 31, 2018, the Company had unrecognized tax benefits of approximately $63 million, primarily related to research and development credits. 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. The Company has not recognized any interest or penalties relating to unrecognized tax benefits in its consolidated financial statements. Any interest or penalties would be recognized as a component of income tax expense.

Derivative instruments

Derivative instruments. The Company recognizes its derivative instruments, other than commodity derivative contracts that are designated as normal purchase and normal sale contracts, as either assets or liabilities measured at fair value. The Company nets the fair value of the derivative instruments by counterparty in the accompanying consolidated balance sheets when the right of offset exists. The Company does not have any derivatives designated as fair value or cash flow hedges. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated balance sheets.

Asset retirement obligations

Asset retirement obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related oil and natural gas property asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are recognized as an increase in the carrying amount of the liability through accretion expense. Based on certain factors, including commodity prices and costs, the Company may revise its previous estimates of the liability, which would also increase or decrease the related oil and natural gas property asset.

Treasury stock

Treasury stock. Treasury stock purchases are recorded at cost.

Revenue recognition

Revenue recognition. On January 1, 2018, the Company adopted ASC Topic 606, “Revenue from Contracts with Customers,” (“ASC 606”) using the modified retrospective approach, which only applies to contracts that were not completed as of the date of initial application. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment and does not have a material impact on the Company’s reported net income (loss), cash flows from operations or statement of stockholders’ equity.

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. Prior to the adoption of ASC 606, the Company recorded oil and natural gas revenues at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. The Company followed the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.

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 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 December 31, 2018, the Company had receivables related to contracts with customers of approximately $466 million.

The following table shows the impact of the adoption of ASC 606 on the Company’s current period results as compared to the previous revenue recognition standard, ASC Topic 605, “Revenue recognition” (“ASC 605”):


		Year Ended
		December 31, 2018
		Under		Under		Increase
(in millions)		ASC 606		ASC 605		(Decrease)

Operating revenues:
	Oil sales	$	3,443	$	3,432	$	11
	Natural gas sales		708		674		34

Operating costs and expenses:
	Oil and natural gas production		590		600		(10)
	Gathering, processing and transportation		55		-		55

Net income		$	2,286	$	2,286	$	-

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 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 reductions of general and administrative expense. Such fees totaled approximately $19 million, $16 million and $17 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]

Stock-based compensation. Stock-based compensation expense is recognized in the Company’s financial statements on an accelerated basis over the awards’ vesting periods based on their grant date fair values. Stock-based compensation awards vest over a period generally ranging from one to five years. The Company utilizes the average of the high and low stock prices at each grant date to determine the fair value of restricted stock and the Monte Carlo simulation method to determine the fair value of performance unit awards. The Company recognizes forfeitures on stock-based compensation awards as they occur. When the Company adopted ASU No. 2016-09, “Compensation–Stock Compensation (Topic 718): Improvements to Employee Share-based Payment Accounting,” (“ASU 2016-09”) on January 1, 2017, it recorded a cumulative effect adjustment, which decreased retained earnings by less than $1 million, increased additional paid-in capital by approximately $8 million and decreased net deferred income tax liabilities by approximately $8 million.

Recent accounting pronouncements