UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended ~~September 30, 2018~~March 31, 2019

☐

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

For the transition period from to

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)


Delaware		76-0818600
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

One Concho Center
600 West Illinois Avenue
Midland, Texas		79701
(Address of principal executive offices)		(Zip Code)

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

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

Large accelerated filer ☑	Accelerated filer ☐

Non-accelerated filer ☐	Smaller reporting company ☐

Emerging growth company ☐

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

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

Number of shares of the registrant’s common stock outstanding at ~~October~~April 29, ~~2018~~2019: ~~200,250,195~~200,594,025 shares

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION:		iii

	Item 1. Consolidated Financial Statements (Unaudited)	iii

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	3633

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	5849

	Item 4. Controls and Procedures	6051

PART II – OTHER INFORMATION:		6152

	Item 1. Legal Proceedings	6152

	Item 1A. Risk Factors	6152

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	6253

	Item 6. Exhibits	6354

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements and information contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our future financial position, operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims, disputes and derivative activities. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “will,” “goal” or other words that convey future events, expectations or possible outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events and their potential effect on us. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by any forward-looking statements. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made. We disclaim any obligation to update or revise these statements unless required by law, whether as a result of new information, future events or otherwise, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Part II, Item 1A. Risk Factors” in this Quarterly Report and in “Part I, Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2017 and “Part II, Item 1A. Risk Factors” in our subsequent Quarterly Reports on Form 10-Q, and the other information included in our filings with the Securities and Exchange Commission and our public disclosure,2018, as well as those factors summarized below:

· ~~disruptions to, capacity constraints~~declines in, the sustained depression of, or ~~other limitations on~~increased volatility in the ~~pipeline systems that deliver~~prices we receive for our oil ~~natural gas liquids~~ and natural gas, ~~and other processing and transportation considerations;~~

·~~risks related to ongoing expansion of our business, including the recruitment and retention of qualified personnel~~or increases in the ~~Permian Basin;~~differential between index oil or natural gas prices and prices received;

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

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

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

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

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

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

·competition in the oil and natural gas industry;

·risks related to the concentration of our ~~recent acquisition~~operations in the Permian Basin of ~~RSP Permian, Inc., such as increased expenses~~West Texas and ~~integration efforts, failure to realize the expected benefits of the transaction, liabilities associated with acquired properties or businesses and the ability to realize expected benefits;~~Southeast New Mexico;

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

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

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

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

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

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

·the impact of current and potential changes to federal or state tax rules and ~~regulations, including the Tax Cuts and Jobs Act;~~regulations;

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

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

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

· the impact of potential changes in our credit ratings;

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

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

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

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

·~~competition in the oil and natural gas industry;~~ and

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

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

PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

Consolidated Balance Sheets at ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017~~2018	1

Consolidated Statements of Operations for the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~	2

Consolidated ~~Statement~~Statements of Stockholders’ Equity for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2019 and 2018	3

Consolidated Statements of Cash Flows for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~	4

Condensed Notes to Consolidated Financial Statements	5

iii

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited


				September 30,		December 31,					March 31,		December 31,
(in millions, except share and per share amounts)	(in millions, except share and per share amounts)				2018	2017		(in millions, except share and per share amounts)			2019		2018
Assets	Assets							Assets
Current assets:	Current assets:							Current assets:
								Cash and cash equivalents			$	-	$	-
	Cash and cash equivalents			$	24	$	-	Accounts receivable, net of allowance for doubtful accounts:
	Accounts receivable, net of allowance for doubtful accounts:								Oil and natural gas			530		466
		Oil and natural gas			520		331		Joint operations and other			413		365
		Joint operations and other			387		212	Inventory				34		35
	Inventory				36		14	Derivative instruments				1		484
	Prepaid costs and other				61		35	Prepaid costs and other				49		59
			Total current assets		1,028		592			Total current assets		1,027		1,409
Property and equipment:	Property and equipment:							Property and equipment:
	Oil and natural gas properties, successful efforts method				30,980		21,267	Oil and natural gas properties, successful efforts method				32,559		31,706
	Accumulated depletion and depreciation				(9,362)		(8,460)	Accumulated depletion and depreciation				(10,138)		(9,701)
		Total oil and natural gas properties, net			21,618		12,807		Total oil and natural gas properties, net			22,421		22,005
	Other property and equipment, net				277		234	Other property and equipment, net				350		308
		Total property and equipment, net			21,895		13,041		Total property and equipment, net			22,771		22,313
Deferred loan costs, net	Deferred loan costs, net				11		13	Deferred loan costs, net				9		10
Goodwill	Goodwill				2,246		-	Goodwill				2,229		2,224
Intangible assets, net	Intangible assets, net				20		26	Intangible assets, net				18		19
Noncurrent derivative instruments								Noncurrent derivative instruments				2		211
Other assets	Other assets				10		60	Other assets				112		108
	Total assets			$	25,210	$	13,732	Total assets			$	26,168	$	26,294
Liabilities and Stockholders’ Equity	Liabilities and Stockholders’ Equity							Liabilities and Stockholders’ Equity
Current liabilities:	Current liabilities:							Current liabilities:
	Accounts payable - trade			$	44	$	43	Accounts payable - trade			$	61	$	50
	Bank overdrafts				87		116	Bank overdrafts				105		159
	Revenue payable				283		183	Revenue payable				258		253
	Accrued drilling costs				548		330	Accrued drilling costs				605		574
	Derivative instruments				547		277	Derivative instruments				292		-
	Other current liabilities				367		216	Other current liabilities				339		320
			Total current liabilities		1,876		1,165			Total current liabilities		1,660		1,356
Long-term debt	Long-term debt				4,143		2,691	Long-term debt				4,567		4,194
Deferred income taxes	Deferred income taxes				1,431		687	Deferred income taxes				1,612		1,808
Noncurrent derivative instruments	Noncurrent derivative instruments				363		102	Noncurrent derivative instruments				75		-
Asset retirement obligations and other long-term liabilities	Asset retirement obligations and other long-term liabilities				165		172	Asset retirement obligations and other long-term liabilities				195		168
Commitments and contingencies (Note 10)
Commitments and contingencies (Note 9)								Commitments and contingencies (Note 9)
Stockholders’ equity:	Stockholders’ equity:							Stockholders’ equity:
	Common stock, $0.001 par value; 300,000,000 authorized; 201,268,321 and							Common stock, $0.001 par value; 300,000,000 authorized; 201,755,333 and
		149,324,849 shares issued at September 30, 2018 and December 31, 2017,							201,288,884 shares issued at March 31, 2019 and December 31, 2018,
		respectively			-		-		respectively			-		-
	Additional paid-in capital				14,749		7,142	Additional paid-in capital				14,797		14,773
	Retained earnings				2,613		1,840	Retained earnings				3,406		4,126
	Treasury stock, at cost; 1,028,138 and 598,049 shares at September 30, 2018 and							Treasury stock, at cost; 1,155,813 and 1,031,655 shares at March 31, 2019 and
		December 31, 2017, respectively			(130)		(67)		December 31, 2018, respectively			(144)		(131)
			Total stockholders’ equity		17,232		8,915			Total stockholders’ equity		18,059		18,768
	Total liabilities and stockholders’ equity			$	25,210	$	13,732	Total liabilities and stockholders’ equity			$	26,168	$	26,294

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

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited


			Three Months Ended				Nine Months Ended						Three Months Ended
			September 30,				September 30,						March 31,
(in millions, except per share amounts)	(in millions, except per share amounts)			2018		2017		2018		2017	(in millions, except per share amounts)			2019		2018

Operating revenues:	Operating revenues:										Operating revenues:
	Oil sales		$	957	$	498	$	2,545	$	1,461	Oil sales		$	935	$	793
	Natural gas sales			235		129		539		345	Natural gas sales			169		154
		Total operating revenues		1,192		627		3,084		1,806		Total operating revenues		1,104		947
Operating costs and expenses:	Operating costs and expenses:										Operating costs and expenses:
	Oil and natural gas production			156		106		416		293	Oil and natural gas production			174		130
	Production and ad valorem taxes			89		48		229		140	Production and ad valorem taxes			86		70
	Gathering, processing and transportation			16		-		36		-	Gathering, processing and transportation			26		11
	Exploration and abandonments			10		7		36		42	Exploration and abandonments			47		18
	Depreciation, depletion and amortization			406		284		1,033		848	Depreciation, depletion and amortization			465		317
	Accretion of discount on asset retirement obligations			3		2		7		6	Accretion of discount on asset retirement obligations			3		2
	General and administrative (including non-cash stock-based										General and administrative (including non-cash stock-based compensation of $24 and
		compensation of $23 and $17 for the three months ended										$17 for the three months ended March 31, 2019 and 2018, respectively)		91		65
		September 30, 2018 and 2017, respectively, and $58 and $43									Loss on derivatives			1,059		35
		for the nine months ended September 30, 2018 and 2017,									Gain on disposition of assets, net			(1)		(723)
		respectively)		84		64		221		180	Transaction costs			-		7
	(Gain) loss on derivatives			625		206		793		(289)		Total operating costs and expenses		1,950		(68)
	(Gain) loss on disposition of assets, net			5		(13)		(719)		(667)
	Transaction costs			23		-		39		2
		Total operating costs and expenses		1,417		704		2,091		555
Income (loss) from operations	Income (loss) from operations			(225)		(77)		993		1,251	Income (loss) from operations			(846)		1,015
Other income (expense):	Other income (expense):										Other income (expense):
	Interest expense			(46)		(39)		(103)		(118)
	Loss on extinguishment of debt			-		(65)		-		(66)	Interest expense			(47)		(30)
	Other, net			3		2		108		20	Other, net			4		104
		Total other income (expense)		(43)		(102)		5		(164)		Total other income (expense)		(43)		74
Income (loss) before income taxes	Income (loss) before income taxes			(268)		(179)		998		1,087	Income (loss) before income taxes			(889)		1,089
	Income tax (expense) benefit			69		66		(225)		(398)	Income tax (expense) benefit			194		(254)
Net income (loss)	Net income (loss)		$	(199)	$	(113)	$	773	$	689	Net income (loss)		$	(695)	$	835
Earnings per share:	Earnings per share:										Earnings per share:
	Basic net income (loss)		$	(1.05)	$	(0.77)	$	4.74	$	4.64	Basic net income (loss)		$	(3.49)	$	5.60
	Diluted net income (loss)		$	(1.05)	$	(0.77)	$	4.74	$	4.63	Diluted net income (loss)		$	(3.49)	$	5.58

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

Concho Resources Inc.

Consolidated ~~Statement~~Statements of Stockholders’ Equity

Unaudited


			Common Stock			Additional								Total				Common Stock			Additional								Total
			Issued			Paid-in		Retained			Treasury Stock			Stockholders’				Issued			Paid-in		Retained			Treasury Stock			Stockholders’
(in millions, except share data)	(in millions, except share data)		Shares	Amount		Capital		Earnings			Shares	Amount		Equity		(in millions, except share data)		Shares	Amount		Capital		Earnings			Shares	Amount		Equity
		(in thousands)								(in thousands)							(in thousands)								(in thousands)
BALANCE AT DECEMBER 31, 2017	BALANCE AT DECEMBER 31, 2017		149,325	$	-	$	7,142	$	1,840		598	$	(67)	$	8,915	BALANCE AT DECEMBER 31, 2017		149,325	$	-	$	7,142	$	1,840		598	$	(67)	$	8,915
	Net income		-		-		-		773		-		-		773	Net income		-		-		-		835		-		-		835
	Common stock issued in business combination		50,915		-		7,549		-		-		-		7,549	Grants of restricted stock		112		-		-		-		-		-		-
	Grants of restricted stock		646		-		-		-		-		-		-	Performance unit share conversion		446		-		-		-		-		-		-
	Performance unit share conversion		446		-		-		-		-		-		-	Cancellation of restricted stock		(13)		-		-		-		-		-		-
	Cancellation of restricted stock		(64)		-		-		-		-		-		-	Stock-based compensation		-		-		17		-		-		-		17
	Stock-based compensation		-		-		58		-		-		-		58	Purchase of treasury stock		-		-		-		-		202		(29)		(29)
BALANCE AT MARCH 31, 2018																BALANCE AT MARCH 31, 2018		149,870	$	-	$	7,159	$	2,675		800	$	(96)	$	9,738
	Purchase of treasury stock		-		-		-		-		430		(63)		(63)
BALANCE AT SEPTEMBER 30, 2018			201,268	$	-	$	14,749	$	2,613		1,028	$	(130)	$	17,232
BALANCE AT DECEMBER 31, 2018																BALANCE AT DECEMBER 31, 2018		201,289	$	-	$	14,773	$	4,126		1,032	$	(131)	$	18,768
																Net loss		-		-		-		(695)		-		-		(695)
																Common stock dividends ($0.125 per share)		-		-		-		(25)		-		-		(25)
																Grants of restricted stock		235		-		-		-		-		-		-
																Performance unit share conversion		246		-		-		-		-		-		-
																Cancellation of restricted stock		(15)		-		-		-		-		-		-
																Stock-based compensation		-		-		24		-		-		-		24
																Purchase of treasury stock		-		-		-		-		124		(13)		(13)
BALANCE AT MARCH 31, 2019																BALANCE AT MARCH 31, 2019		201,755	$	-	$	14,797	$	3,406		1,156	$	(144)	$	18,059

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

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited


					Nine Months Ended								Three Months Ended
					September 30,								March 31,
(in millions)	(in millions)				2018		2017		(in millions)				2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES:	CASH FLOWS FROM OPERATING ACTIVITIES:								CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income				$	773	$	689
	Adjustments to reconcile net income to net cash provided by operating activities:								Net income (loss)				$	(695)	$	835
		Depreciation, depletion and amortization				1,033		848	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Accretion of discount on asset retirement obligations				7		6		Depreciation, depletion and amortization				465		317
		Exploration and abandonments, including dry holes				20		29		Accretion of discount on asset retirement obligations				3		2
		Non-cash stock-based compensation expense				58		43		Exploration and abandonments				38		10
		Deferred income taxes				225		392		Non-cash stock-based compensation expense				24		17
		Gain on disposition of assets, net				(719)		(667)		Deferred income taxes				(194)		254
		(Gain) loss on derivatives				793		(289)		Gain on disposition of assets, net				(1)		(723)
		Net settlements received from (paid on) derivatives				(238)		126		Loss on derivatives				1,059		35
		Loss on extinguishment of debt				-		66		Net settlements paid on derivatives				-		(112)
		Other				(94)		1		Other				2		(96)
	Changes in operating assets and liabilities, net of acquisitions and dispositions:								Changes in operating assets and liabilities, net of acquisitions and dispositions:
			Accounts receivable			(57)		(61)			Accounts receivable			(111)		(81)
			Prepaid costs and other			(15)		(1)			Prepaid costs and other			9		(2)
			Inventory			(12)		(1)			Inventory			-		3
			Accounts payable			(27)		7			Accounts payable			11		(12)
			Revenue payable			62		5			Revenue payable			8		2
			Other current liabilities			52		(8)			Other current liabilities			5		39
				Net cash provided by operating activities		1,861		1,185				Net cash provided by operating activities		623		488
CASH FLOWS FROM INVESTING ACTIVITIES:	CASH FLOWS FROM INVESTING ACTIVITIES:								CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to oil and natural gas properties					(1,669)		(1,092)	Additions to oil and natural gas properties					(885)		(474)
	Acquisitions of oil and natural gas properties					(105)		(866)	Acquisitions of oil and natural gas properties					(5)		(13)
	Additions to property, equipment and other assets					(53)		(34)	Additions to property, equipment and other assets					(15)		(6)
	Proceeds from the disposition of assets					260		803	Proceeds from the disposition of assets					5		255
	Direct transaction costs for disposition of assets					(3)		(18)	Direct transaction costs for disposition of assets					(2)		(3)
	Distribution from equity method investment					148		-	Distribution from equity method investment					-		148
				Net cash used in investing activities		(1,422)		(1,207)				Net cash used in investing activities		(902)		(93)
CASH FLOWS FROM FINANCING ACTIVITIES:	CASH FLOWS FROM FINANCING ACTIVITIES:								CASH FLOWS FROM FINANCING ACTIVITIES:
	Borrowings under credit facility					2,408		473	Borrowings under credit facility					1,112		662
	Payments on credit facility					(2,537)		(105)	Payments on credit facility					(739)		(984)
	Issuance of senior notes, net					1,595		1,794	Payment of common stock dividends					(25)		-
	Repayments of senior notes					-		(2,150)	Purchases of treasury stock					(13)		(29)
	Repayments of RSP debt					(1,690)		-	Decrease in bank overdrafts					(54)		(44)
	Debt extinguishment costs					(83)		(63)	Other					(2)		-
	Payments for loan costs					(16)		(25)				Net cash provided by (used in) financing activities		279		(395)
	Purchase of treasury stock					(63)		(23)				Net increase in cash and cash equivalents		-		-
	Increase (decrease) in bank overdrafts					(29)		68
				Net cash used in financing activities		(415)		(31)
				Net increase (decrease) in cash and cash equivalents		24		(53)
Cash and cash equivalents at beginning of period	Cash and cash equivalents at beginning of period					-		53	Cash and cash equivalents at beginning of period					-		-
Cash and cash equivalents at end of period	Cash and cash equivalents at end of period				$	24	$	-	Cash and cash equivalents at end of period				$	-	$	-
NON-CASH INVESTING AND FINANCING ACTIVITIES:
	Issuance of common stock for business combinations				$	7,549	$	291

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

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

Note 1. Organization and nature of operations

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

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

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

Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The 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~~2019 presentation. These reclassifications had no impact on net income (loss), total assets, liabilities and stockholders’ equity or total cash flows.

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

Interim financial statements. The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, ~~2017~~2018 is derived from audited consolidated financial statements. In the opinion of management, the accompanying consolidated financial statements reflect all adjustments necessary to present fairly the Company’s consolidated financial statements. All such adjustments are of a normal, recurring nature. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed in or omitted from these consolidated financial statements. Accordingly, these condensed notes to the consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in the Company’s ~~Annual Report on~~2018 Form ~~10-K for the year ended December 31, 2017.~~

~~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.10-K.

~~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 September 30, 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

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2018~~

~~Unaudited~~

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 reporting unit’s fair value is calculated as the combined market capitalization of the Company’s equity plus a control premium plus the fair value of the Company’s long-term debt. As the Company has elected to early adopt Accounting Standards Update (“ASU”) No. 2017-04, “Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (“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 then reduced by an amount that is equal to the amount by which the carrying value of the reporting unit exceeds the fair value.

Equity method investments. The Company accounts for its equity method investments under the equity method of accounting and includes the investment balance in other assets on the consolidated balance sheets. Gains and losses incurred from the Company’s equity investments are recorded in other income (expense) on the consolidated statements of operations.

~~The~~At March 31, 2019, the Company ~~owns~~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 ~~Southern~~ 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.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

The Company’s net investment in Oryx was ~~approximately~~ ~~$49 million~~zero at March 31, 2019 and December 31, ~~2017.~~2018. The Company recorded income of approximately $2 million for the three months ended September 30, 2017 and $5 million and $4 million for the nine months ended September 30, 2018 and 2017, respectively. The Company willdid not record income or loss on the Oryx investment ~~until such~~for the three months ended March 31, 2019, as cumulative net income ~~is greater than~~had yet to exceed the distribution in excess of the Company’s investment. In April 2019, Oryx entered into an agreement to sell 100 percent of its ~~investment.~~equity interests, which included the Company’s 23.75 percent membership interest.

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 Northern Delaware Basin. See Note 5 for additional information regarding the disposition of ACC.

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 109 for additional information.

Revenue recognition. On January 1, 2018, the Company adopted Accounting Standards Codification (“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 Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with Customers,” (“ASC ~~606.~~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

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2018~~

~~Unaudited~~

after production. At ~~September 30,~~March 31, 2019 and December 31, 2018, the Company had receivables related to contracts with customers of approximately ~~$520 million.~~$530 million and $466 million, respectively.

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”):

Three Months Ended

Nine Months Ended

September 30, 2018

September 30, 2018

Under

Under

Increase

Under

Under

Increase
(in millions)
ASC 606

ASC 605

(Decrease)

ASC 606

ASC 605

(Decrease)



Operating revenues:

Oil sales
$
957

$
952

$
5

$
2,545

$
2,537

$
8

Natural gas sales

235

227

8

539

519

20

Operating costs and expenses:

Oil and natural gas production

156

159

(3)

416

424

(8)

Gathering, processing and transportation

16

-

16

36

-

36

Net income (loss)
$
(199)

$
(199)

$
-

$
773

$
773

$
-

Oil Contracts. The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing which is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred after the transfer of control of the oil, the differentials are included in oil sales on the consolidated statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in gathering, processing and transportation on the Company’s consolidated statements of operations as they represent payment for services performed outside of the contract with the customer.

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

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

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and records such reimbursements as reductions to general and administrative expense. Such fees totaled approximately $4 million for each of the three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017 and $13 million and $12 million for the nine months ended September 30, 2018 and 2017, respectively.~~2018.

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2018~~

~~Unaudited~~

Recently adopted accounting pronouncements. In ~~January 2017,~~February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2017-04, which simplifies how an entity subsequently measures goodwill by eliminating Step 2 from the goodwill impairment test. In place of Step 2, under this standard 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. This standard should be applied on a prospective basis and is effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted after January 1, 2017. The Company has elected to early adopt this standard beginning in the third quarter of 2018. The early adoption of this standard did not have an impact on the Company’s financial results.

~~New accounting pronouncements issued but not yet adopted.~~ ~~In February 2016, the FASB issued ASU~~Accounting Standards Update (“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 consolidated balance sheet while maintaining ~~substantially~~ similar classifications for ~~financing~~finance and operating leases. Lease expense recognition on the consolidated statements of operations ~~will be~~was effectively unchanged. ~~This guidance is effective for reporting periods beginning after December 15, 2018, and early adoption is permitted.~~ The Company ~~does not plan to early adopt the standard.~~adopted this guidance on January 1, 2019. The Company ~~plans to make~~made policy elections not to ~~not~~ capitalize short-term leases for all asset classes and not to ~~not~~ separate non-lease components from lease components for all asset classes except for vehicles. The Company also ~~plans to~~did not elect the package of practical expedients that ~~allows~~allowed 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 substantially completed the process of reviewing and determining the contracts to which this new guidance applies. The Company is currently enhancing its accounting system in order to track and calculate additional information necessary for adoption of this standard. Upon adoption, the Company will be required to recognize right-of-use assets and associated lease liabilities that are not currently recognized under applicable guidance. The Company does not believe this adoption will have a material impact on its consolidated balance sheets based on the leases in place as of the filing of this Quarterly Report.

In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient not to ~~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~~elected this practical expedient, which ~~becomes~~became effective upon the date of adoption of ASU 2016-02. ~~After the adoption of ASU 2016-02, the~~The Company will assess any new land easements to determine whether the arrangement should be accounted for as a lease. In July 2018, the FASB issued ASU No. 2018-11, “Targeted Improvements,” which provides a transition election not to ~~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 ~~expects to elect~~elected this transition approach, ~~and recognize~~however the cumulative impact of adoption in the opening balance of retained earnings as of January 1, ~~2019.~~2019 was zero.

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

In ~~July~~August 2018, the FASB issued ASU No. 2018-09, “Codification Improvements,” 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.

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” 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. 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.

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2018~~

~~Unaudited~~

~~On August 17, 2018, the U.S.~~ Securities and Exchange Commission ~~(the “SEC”~~(“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.~~equity to interim periods. The registrants ~~will be~~are required to analyze changes in stockholders’ equity in the form of a reconciliation for the current quarter and year-to-date interim periods and comparative periods in the prior year. ~~The~~As a result, the Company updated its presentation of the consolidated statements of stockholders’ equity to include comparative periods in the prior year. In addition, the final rule requires the presentation of dividends per share to be disclosed in the statement of stockholders’ equity.

New accounting pronouncements issued but not yet adopted. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (“Topic 326”), which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. In November 2018, the FASB issued ASU No. 2018-19, “Codification Improvements to Topic 326, Financial Instruments–Credit Losses,” which makes amendments to clarify the scope of the guidance, including the amendment clarifying that receivables arising from operating leases are not within the scope of Topic 326. This guidance is effective for ~~all filings submitted on or~~fiscal years beginning after ~~November 5,~~December 15, 2019, and early adoption is allowed as early as fiscal years beginning after December 15, 2018. The Company ~~is currently analyzing the final rule and~~does not believe this new guidance will ~~comply with the new disclosure requirements for all filings after the effective date.~~ have a material impact on its consolidated financial statements.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

~~Note 3.~~ ~~Exploratory well costs~~

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 ~~capitalizes exploratory well costs until a determination~~ is made that the well has either found proved reserves or that it is impaired. After an exploratory well has been completed and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas reserves can be classified as proved. In those circumstances, the Company continues to capitalize the well or project costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progresscurrently assessing the ~~reserves~~effect that ASU 2018-18 will have on its financial position, results of operations and ~~the economic and operating viability of the project.~~The capitalized exploratory well costs are carried in unproved oil and natural gas properties. See Note 16 for the proved and unproved components of oil and natural gas properties. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments expense in the consolidated statements of operations.

~~The following table reflects the Company’s net capitalized exploratory well activity during the nine months ended September 30, 2018:~~

Nine Months Ended
(in millions)

September 30, 2018

Beginning capitalized exploratory well costs

$
182

Additions to exploratory well costs pending the determination of proved reserves

321

Reclassifications due to determination of proved reserves

(163)

Disposition of wells

(14)
Ending capitalized exploratory well costs

$
326

~~The following table provides an aging at September 30, 2018 and December 31, 2017 of capitalized exploratory well costs based on the date drilling was completed:~~disclosures.

September 30,

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

2017

Capitalized exploratory well costs that have been capitalized for a period of one year
$
326

$
180

or less

Capitalized exploratory well costs that have been capitalized for a period greater

than one year

-

2

Total capitalized exploratory well costs
$
326

$
182
Number of projects with exploratory well costs that have been capitalized for a period

greater than one year

-

2

108

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

Note 4.3. RSP Acquisition

On July 19, 2018, the Company completed the acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”). 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 Southern 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 for 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 9 for additional information regarding the Company’s debt activity.

In connection with the RSP Acquisition, the Company incurred approximately $23 million and $33 million of costs related to consulting, investment banking, advisory, legal and other acquisition-related fees during the three and nine months ended September 30, 2018, respectively, 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, and includes, but is not limited to, valuation of pre-acquisition contingencies, final tax returns that provide the underlying tax basis of RSP’s assets and liabilities and final appraisals of assets acquired and liabilities assumed. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities, including goodwill, may be revised as appropriate.

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


(in millions)

Total purchase price			$	7,549

Fair value of liabilities assumed:
	Accounts payable – trade		$	48
	Accrued drilling costs			79
	Current derivative instruments			10
	Other current liabilities			124
	Long-term debt			1,758
	Deferred income taxes			514
	Asset retirement obligations			20
	Noncurrent derivative instruments			5
		Total liabilities assumed	$	2,558

		Total purchase price plus liabilities assumed	$	10,107

Fair value of assets acquired:
	Accounts receivable		$	194
	Current derivative instruments			36
	Other current assets			21
	Proved oil and natural gas properties			4,055
	Unproved oil and natural gas properties			3,565
	Other property and equipment			5
	Noncurrent derivative instruments			2
	Implied goodwill			2,229
		Total assets acquired	$	10,107

119

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~

~~Unaudited~~

~~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

$
25

Accrued drilling costs

131

Current derivative instruments

10

Other current liabilities

130

Long-term debt

1,758

Deferred income taxes

518

Asset retirement obligations


16

Noncurrent derivative instruments

5

Total liabilities assumed

$
2,593

Total purchase price plus liabilities assumed

$
10,142

Fair value of assets acquired:

Accounts receivable

$
213

Current derivative instruments

36

Other current assets

21

Proved oil and natural gas properties


4,052

Unproved oil and natural gas properties


3,565

Other property and equipment

5

Noncurrent derivative instruments

2

Other long-term assets

2

Implied goodwill

2,246

Total assets acquired

$
10,142

~~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 New York Mercantile Exchange (“NYMEX”) strip pricing and consensus pricing to value the reserves, 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 $16 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.

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2018~~

~~Unaudited~~

~~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 $22 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 11 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 already operates.

Approximately $250 million of operating revenues and approximately $15 million of loss 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 September 30, 2018.

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2018~~March 31, 2019

Unaudited

Pro forma data. The following unaudited pro forma combined condensed financial data for the three ~~and nine~~ months ended ~~September 30,~~March 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 natural 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 $23 million and $33 million for the three and nine months ended September 30, 2018, respectively, and acquisition-related costs incurred by RSP and severance payments to certain RSP employees that totaled approximately $52 million and $56 million for the three and nine months ended September 30, 2018, respectively. The pro forma results of operations do not include any cost savings or other synergies that may result from the RSP ~~Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the RSP assets.~~Acquisition. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the ~~periods presented, as they were primarily acreage acquisitions and their results were not deemed material.~~period. The pro forma combined condensed financial data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the RSP Acquisition taken place on January 1, 2017 and is not intended to be a projection of future results.

Three Months Ended

Nine Months Ended

September 30,

September 30,
(in millions, except per share amounts)

2018

2017

2018

2017

Operating revenues

$
1,243

$
829

$
3,741

$
2,361
Net income (loss)

$
(133)

$
(94)

$
1,039

$
780
Earnings per share:


Basic net income (loss)

$
(0.67)

$
(0.47)

$
5.19

$
3.92

Diluted net income (loss)

$
(0.67)

$
(0.47)

$
5.19

$
3.91


		Three Months Ended
(in millions, except per share amounts)		March 31, 2018

Operating revenues		$	1,226
Net income		$	931
Earnings per share:
	Basic net income	$	4.66
	Diluted net income	$	4.64

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Note 5.4. Other acquisitions, divestitures and nonmonetary transactions

During the ~~nine~~three months ended ~~September 30,~~March 31, 2018, the Company ~~entered into~~closed the following ~~transactions (exclusive of the RSP Acquisition disclosed in Note 4):~~transactions:

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 of certain producing wells and approximately 34,000 net acres located primarily ~~comprised of approximately 32,000 net acres~~ in the ~~Northern~~northern portion of the Delaware ~~Basin, with current production of 3 MBoepd.~~Basin. The business acquired was valued at approximately $755 million as compared to the historical book value of the divested assets of approximately $180 million, which resulted in a non-cash gain of approximately $575 ~~million. 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 receivedincluded in ~~the business combination approximated the fair value~~gain on disposition of assets, ~~disposed.~~net on the Company’s consolidated statement of operations for the three months ended March 31, 2018.

~~Southern~~ Delaware Basin divestitures. In January 2018, the Company closed on two asset ~~sales transactions~~divestitures of certain non-core assets in Reeves and Ward Counties, Texas, with combined proceeds of approximately $280 million. After direct transaction costs, the Company recorded a pre-tax gain of approximately $134 million, which is included in gain on disposition of assets, net on its consolidated statement of operations for the ~~nine~~three months ended ~~September 30,~~March 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. In connection with the Reverse 1031 Exchange, the Company assigned the

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2018~~

~~Unaudited~~

ownership of the oil and natural gas properties acquired to a VIE formed by an exchange accommodation titleholder. The Company operated the properties pursuant to a management agreement with the VIE. At December 31, 2017 and prior to the completion of the reverse like-kind exchange in January 2018, 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.

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 the ~~nine~~three months ended ~~September 30,~~March 31, 2018, the Company completed multiple nonmonetary transactions. These transactions included ~~the exchange~~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 nine months ended~~ ~~September 30, 2017, the Company entered into the following transactions:~~

~~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~~$14 million, in cash. Concurrent with the acquisition, the Company entered into a transaction structured as a Reverse 1031 Exchange, which was completed in January 2018 upon the closing of its Southern Delaware Basin divestitures.

~~Northern 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 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 of approximately $655 million, which is included in gain on disposition of assets, net on ~~its~~the Company’s consolidated statement of operations for the ~~nine~~three months ended ~~September 30, 2017. The Company’s net investment in ACC at the time of closing was approximately $129 million.~~March 31, 2018.

1511

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

Note 6.5. Stock incentive plan

The Company’s 2015 Stock Incentive Plan (“the Plan”) provides for granting stock options, restricted stock awards and performance unit awards to directors, officers and employees of the Company. The restricted ~~stock-based compensation~~stock awards ~~generally~~ vest over a period ranging from one to ~~eight~~ten years. ~~Performance~~The holders of unvested restricted stock awards have voting rights and the right to receive dividends.

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

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

A summary of the Company’s restricted stock shares and performance unit activity under the Plan for the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2019 is presented below:

Restricted

Performance

Stock Shares

Units

Outstanding at December 31, 2017


1,149,246

247,647

Awards granted (a)


645,584
(b)

111,490

Awards cancelled / forfeited


(64,379)

-

Lapse of restrictions

(368,665)

-

Outstanding at September 30, 2018

1,361,786

359,137

(a) Weighted average grant date fair value per share/unit

$
137.89

$
216.03

(b) Includes 167,122 restricted stock shares granted to certain RSP employees on July 20, 2018.


		Restricted			Performance
		Stock Shares			Units

Outstanding at December 31, 2018			1,364,699		218,391
	Awards granted (a)		235,082		212,947	(b)
	Awards cancelled / forfeited		(14,947)		-
	Lapse of restrictions		(146,048)		-
Outstanding at March 31, 2019		1,438,786		431,338

(a)	Weighted average grant date fair value per share/unit	$	105.52	$	144.03

(b)	Includes 38,952 performance award units granted to certain officers in January 2019 that may convert into shares of restricted stock awards at the end of each performance period that will be subject to additional vesting conditions.

The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at ~~September 30, 2018:~~March 31, 2019:


(in millions)	(in millions)			(in millions)

Remaining 2018		$	25
2019			63
Remaining 2019				Remaining 2019	$	61
2020	2020		33	2020		48
2021	2021		10	2021		22
2022				2022		4
2023				2023		2
2024				2024		1
Thereafter	Thereafter		1	Thereafter		2
	Total	$	132	Total	$	140

1612

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

Note 7.6. Disclosures about fair value measurements

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

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

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

Level 3: Prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) ~~volatility factors and (iv)~~ current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

1713

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

Financial Assets and Liabilities Measured at Fair Value

The following table presents the carrying amounts and fair values of the Company’s financial instruments at ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017:~~2018:


			September 30, 2018				December 31, 2017						March 31, 2019				December 31, 2018
			Carrying		Fair		Carrying		Fair				Carrying		Fair		Carrying		Fair
(in millions)	(in millions)		Value		Value		Value		Value		(in millions)		Value		Value		Value		Value

Assets:											Assets:
												Derivative instruments	$	3	$	3	$	695	$	695

Liabilities:											Liabilities:
		Derivative instrument liabilities	$	910	$	910	$	379	$	379		Derivative instruments	$	367	$	367	$	-	$	-
		Credit facility	$	193	$	193	$	322	$	322		Credit facility	$	615	$	615	$	242	$	242
		$600 million 4.375% senior notes due 2025 (a)	$	593	$	605	$	593	$	624		$600 million 4.375% senior notes due 2025 (a)	$	594	$	617	$	594	$	591
		$1,000 million 3.75% senior notes due 2027 (a)	$	988	$	959	$	987	$	1,012		$1,000 million 3.75% senior notes due 2027 (a)	$	989	$	991	$	989	$	939
		$1,000 million 4.3% senior notes due 2028 (a)	$	988	$	996	$	-	$	-		$1,000 million 4.3% senior notes due 2028 (a)	$	988	$	1,033	$	988	$	980
		$800 million 4.875% senior notes due 2047 (a)	$	789	$	814	$	789	$	874		$800 million 4.875% senior notes due 2047 (a)	$	789	$	849	$	789	$	761
		$600 million 4.85% senior notes due 2048 (a)	$	592	$	606	$	-	$	-		$600 million 4.85% senior notes due 2048 (a)	$	592	$	634	$	592	$	573


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

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

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

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

1814

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017.~~2018. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.


September 30, 2018
March 31, 2019																	March 31, 2019
				Fair Value Measurements Using												Net				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable		Total		Consolidated		Consolidated				Identical				Observable		Unobservable		Total		Consolidated		Consolidated
				Assets				Inputs		Inputs		Fair		Balance		Balance				Assets				Inputs		Inputs		Fair		Balance		Balance
(in millions)	(in millions)			(Level 1)				(Level 2)		(Level 3)		Value		Sheet		Sheet	(in millions)			(Level 1)				(Level 2)		(Level 3)		Value		Sheet		Sheet

	Assets:																Assets:
		Current:																Current:
			Commodity derivatives		$	-	$	207	$	-	$	207	$	(207)	$	-			Commodity derivatives		$	-	$	57	$	-	$	57	$	(56)	$	1
		Noncurrent:																Noncurrent:
			Commodity derivatives			-		17		-		17		(17)		-			Commodity derivatives			-		29		-		29		(27)		2

	Liabilities:																Liabilities:
		Current:																Current:
			Commodity derivatives			-		(754)		-		(754)		207		(547)			Commodity derivatives			-		(348)		-		(348)		56		(292)
		Noncurrent:																Noncurrent:
			Commodity derivatives			-		(380)		-		(380)		17		(363)			Commodity derivatives			-		(102)		-		(102)		27		(75)

	Net derivative instruments				$	-	$	(910)	$	-	$	(910)	$	-	$	(910)	Net derivative instruments				$	-	$	(364)	$	-	$	(364)	$	-	$	(364)

1915

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited


December 31, 2017
December 31, 2018																	December 31, 2018
				Fair Value Measurements Using												Net				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable		Total		Consolidated		Consolidated				Identical				Observable		Unobservable		Total		Consolidated		Consolidated
				Assets				Inputs		Inputs		Fair		Balance		Balance				Assets				Inputs		Inputs		Fair		Balance		Balance
(in millions)	(in millions)			(Level 1)				(Level 2)		(Level 3)		Value		Sheet		Sheet	(in millions)			(Level 1)				(Level 2)		(Level 3)		Value		Sheet		Sheet

	Assets:																Assets:
		Current:																Current:
			Commodity derivatives		$	-	$	13	$	-	$	13	$	(13)	$	-			Commodity derivatives		$	-	$	543	$	-	$	543	$	(59)	$	484
		Noncurrent:																Noncurrent:
			Commodity derivatives			-		1		-		1		(1)		-			Commodity derivatives			-		243		-		243		(32)		211

	Liabilities:																Liabilities:
		Current:																Current:
			Commodity derivatives			-		(290)		-		(290)		13		(277)			Commodity derivatives			-		(59)		-		(59)		59		-
		Noncurrent:																Noncurrent:
			Commodity derivatives			-		(103)		-		(103)		1		(102)			Commodity derivatives			-		(32)		-		(32)		32		-

	Net derivative instruments				$	-	$	(379)	$	-	$	(379)	$	-	$	(379)	Net derivative instruments				$	-	$	695	$	-	$	695	$	-	$	695

Concentrations of credit risk. At ~~September 30, 2018~~March 31, 2019, the Company’s primary concentrations of credit risk are the risk of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations.

The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 87 for additional information regarding the Company’s derivative activities and counterparties.

2016

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

Note 8.7. Derivative financial instruments

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

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

The following table summarizes the amounts reported in earnings related to the commodity derivative instruments for the three ~~and nine~~ months ended ~~September 30, 2018~~March 31, 2019 and ~~2017:~~2018:


			Three Months Ended				Nine Months Ended						Three Months Ended
			September 30,				September 30,						March 31,
(in millions)	(in millions)			2018		2017		2018		2017	(in millions)			2019		2018

*Gain (loss) on derivatives:*
*Loss on derivatives:*											*Loss on derivatives:*
	Oil derivatives		$	(626)	$	(205)	$	(787)	$	260	Oil derivatives		$	(1,056)	$	(33)
	Natural gas derivatives			1		(1)		(6)		29	Natural gas derivatives			(3)		(2)
		Total	$	(625)	$	(206)	$	(793)	$	289		Total	$	(1,059)	$	(35)



The following table represents the Company’s net cash receipts from (payments on) derivatives for the three and nine months ended September 30, 2018 and 2017:

The following table represents the Company’s net cash receipts from (payments on) derivatives for the three months ended March 31, 2019 and 2018:											The following table represents the Company’s net cash receipts from (payments on) derivatives for the three months ended March 31, 2019 and 2018:



			Three Months Ended				Nine Months Ended						Three Months Ended
			September 30,				September 30,						March 31,
(in millions)	(in millions)			2018		2017		2018		2017	(in millions)			2019		2018

*Net cash receipts from (payments on) derivatives:*	*Net cash receipts from (payments on) derivatives:*										*Net cash receipts from (payments on) derivatives:*
	Oil derivatives		$	(46)	$	28	$	(245)	$	129	Oil derivatives		$	3	$	(113)
	Natural gas derivatives			2		2		7		(3)	Natural gas derivatives			(3)		1
		Total	$	(44)	$	30	$	(238)	$	126		Total	$	-	$	(112)

2117

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

Commodity derivative ~~contracts at September 30, 2018.~~contracts. The following table sets forth the Company’s outstanding derivative contracts at ~~September 30, 2018~~March 31, 2019. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at ~~September 30, 2018~~March 31, 2019 are expected to settle by December 31, ~~2020.~~2021.

First

Second

Third

Fourth

Quarter

Quarter

Quarter

Quarter

Total
Oil Price Swaps: (a)


2018:


Volume (Bbl)

11,902,007

11,902,007

Price per Bbl

$
56.86
$
56.86

2019:


Volume (Bbl)

11,272,250

10,289,750

9,514,000

8,932,000

40,008,000

Price per Bbl
$
56.14
$
55.83
$
55.61
$
55.44
$
55.78

2020:


Volume (Bbl)

6,680,500

6,344,500

6,049,000

5,814,000

24,888,000

Price per Bbl
$
58.11
$
58.08
$
58.02
$
57.99
$
58.05
Oil Three-Way Collars: (a)


2018:


Volume (Bbl)

1,227,000

1,227,000

Ceiling price per Bbl

$
60.96
$
60.96

Floor price per Bbl

$
48.00
$
48.00

Short put price per Bbl

$
38.00
$
38.00
Oil Costless Collars: (a)


2018:


Volume (Bbl)

1,058,000

1,058,000

Ceiling price per Bbl

$
60.11
$
60.11

Floor price per Bbl

$
46.52
$
46.52

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)

2018:


Volume (Bbl)

10,517,000

10,517,000

Price per Bbl

$
(0.77)
$
(0.77)

2019:

Volume (Bbl)

11,730,000

11,419,500

10,994,000

10,533,000

44,676,500

Price per Bbl
$
(2.93)
$
(3.02)
$
(2.97)
$
(3.07)
$
(2.99)

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)
Natural Gas Price Swaps: (c)

2018:

Volume (MMBtu)

18,458,000

18,458,000

Price per MMBtu

$
3.00
$
3.00

2019:

Volume (MMBtu)

7,291,533

7,231,387

7,178,537

7,089,535

28,790,992

Price per MMBtu
$
2.82
$
2.81
$
2.81
$
2.81
$
2.81

2020:

Volume (MMBtu)

3,276,000

3,276,000

3,128,000

3,128,000

12,808,000

Price per MMBtu
$
2.70
$
2.70
$
2.70
$
2.70
$
2.70



(a) The oil derivative contracts are settled based on the NYMEX – West Texas Intermediate (“WTI”) 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.


				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Price Swaps: (a)
	*2019:*
		Volume (Bbl)		-		15,112,750		13,378,000		11,232,000		39,722,750
		Price per Bbl	$	-	$	56.59	$	56.41	$	55.88	$	56.33
	*2020:*
		Volume (Bbl)		10,502,500		10,166,500		9,453,000		9,218,000		39,340,000
		Price per Bbl	$	57.28	$	57.24	$	57.18	$	57.14	$	57.21
	*2021:*
		Volume (Bbl)		2,160,000		2,184,000		2,024,000		2,024,000		8,392,000
		Price per Bbl	$	54.57	$	54.57	$	54.50	$	54.50	$	54.54
Oil Costless Collars: (a)
	*2019:*
		Volume (Bbl)		-		1,213,250		1,135,000		1,058,000		3,406,250
		Ceiling price per Bbl	$	-	$	64.00	$	63.47	$	62.95	$	63.50
		Floor price per Bbl	$	-	$	56.06	$	55.74	$	55.43	$	55.76
Oil Basis Swaps: (b)
	*2019:*
		Volume (Bbl)		-		11,965,500		12,650,000		15,133,000		39,748,500
		Price per Bbl	$	-	$	(3.03)	$	(2.82)	$	(2.32)	$	(2.69)
	*2020:*
		Volume (Bbl)		13,013,000		10,192,000		10,120,000		10,120,000		43,445,000
		Price per Bbl	$	(0.53)	$	(0.70)	$	(0.71)	$	(0.71)	$	(0.65)
	*2021:*
		Volume (Bbl)		2,070,000		2,093,000		2,116,000		2,116,000		8,395,000
		Price per Bbl	$	0.55	$	0.55	$	0.55	$	0.55	$	0.55
Natural Gas Price Swaps: (c)
	*2019:*
		Volume (MMBtu)		-		17,241,387		17,298,537		17,209,535		51,749,459
		Price per MMBtu	$	-	$	2.87	$	2.87	$	2.87	$	2.87
	*2020:*
		Volume (MMBtu)		6,233,500		6,233,500		6,118,000		6,118,000		24,703,000
		Price per MMBtu	$	2.70	$	2.70	$	2.70	$	2.70	$	2.70


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

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2018~~

~~Unaudited~~

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.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Note 9.8. Debt

The Company’s debt consisted of the following at ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017:~~2018:


				September 30,		December 31,				March 31,		December 31,
(in millions)	(in millions)			2018		2017	(in millions)			2019		2018

Credit facility due 2022	Credit facility due 2022		$	193	$	322	Credit facility due 2022		$	615	$	242
4.375% unsecured senior notes due 2025 (a)	4.375% unsecured senior notes due 2025 (a)			600		600	4.375% unsecured senior notes due 2025 (a)			600		600
3.75% unsecured senior notes due 2027	3.75% unsecured senior notes due 2027			1,000		1,000	3.75% unsecured senior notes due 2027			1,000		1,000
4.3% unsecured senior notes due 2028	4.3% unsecured senior notes due 2028			1,000		-	4.3% unsecured senior notes due 2028			1,000		1,000
4.875% unsecured senior notes due 2047	4.875% unsecured senior notes due 2047			800		800	4.875% unsecured senior notes due 2047			800		800
4.85% unsecured senior notes due 2048	4.85% unsecured senior notes due 2048			600		-	4.85% unsecured senior notes due 2048			600		600
Unamortized original issue discount	Unamortized original issue discount			(10)		(6)	Unamortized original issue discount			(10)		(10)
Senior notes issuance costs, net	Senior notes issuance costs, net			(40)		(25)	Senior notes issuance costs, net			(38)		(38)
	Less: current portion			-		-	Less: current portion			-		-
		Total long-term debt	$	4,143	$	2,691		Total long-term debt	$	4,567	$	4,194


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

Credit facility. The Company’s Credit Facility has a maturity date of May 9, 2022. At ~~September 30, 2018,~~March 31, 2019, the Company’s commitments from its bank group were $2.0 billion, of which $~~1.8~~1.4 billion was unused commitments, net of letters of credit. During the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, the weighted average interest rate on the Credit Facility was ~~4.6~~4.4 percent.At March 31, 2019, certain of the Company’s 100 percent owned subsidiaries were guarantors under the Credit Facility.

Senior notes. Interest on the Company’s senior notes is paid in arrears semi-annually. The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company’s 100 percent owned subsidiaries, subject to customary release provisions as described in Note ~~14.~~13, 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 Company’s 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.

At ~~September 30, 2018~~March 31, 2019, the Company was in compliance with the covenants under all of its debt instruments.

Interest expense. The following amounts have been incurred and charged to interest expense for the three months ended March 31, 2019 and 2018:


		Three Months Ended
		March 31,
(in millions)			2019		2018

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

2319

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

~~Interest expense.~~ ~~The following amounts have been incurred and charged to interest expense for the three and nine months ended~~ ~~September 30, 2018~~ ~~and 2017:~~

Three Months Ended

Nine Months Ended

September 30,

September 30,
(in millions)

2018

2017

2018

2017

Cash payments for interest

$
16

$
73

$
76

$
138
Non-cash interest

1

1


4

5
Net changes in accruals

31

(35)


28

(25)

Interest costs incurred

48

39

108

118
Less: capitalized interest

(2)

-

(5)

-

Total interest expense

$
46

$
39

$
103

$
118

Note ~~10.~~9. Commitments and contingencies

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

~~Mabee Ranch litigation.~~ On July 30, 2018, the owners of certain mineral and surface interests on the Mabee Ranch in Martin and Andrews Counties, Texas filed a lawsuit against the Company in Martin County District Court. These owners claimed that the Company breached certain leases by, among other things, exceeding permitted surface uses, failing to obtain required consents and failing to pay certain royalties due to them. The Company filed its answer to the lawsuit on September 10, 2018; shortly thereafter, the plaintiffs and the Company entered into settlement negotiations. Effective September 28, 2018, the parties executed a settlement agreement that provides for a dismissal of the lawsuit with prejudice.

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 September 30, 2018 and December 31, 2017, the Company had regulatory and environmental liabilities of approximately $32 million and $3 million, respectively.

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2018~~

~~Unaudited~~

Commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including ~~drilling commitments,~~ water commitment agreements, throughput volume delivery commitments, fixed and variable power commitments, sand commitment agreements, fixed asset commitments and maintenance commitments. The Company’s drilling rig commitments are considered leases under ASU 2016-02 and are included within the tables under the “Leases” section below. The following table summarizes the Company’s commitments at ~~September 30, 2018~~March 31, 2019:


(in millions)	(in millions)			(in millions)

Remaining 2018		$	66
2019			79
Remaining 2019				Remaining 2019	$	35
2020	2020		80	2020		75
2021	2021		76	2021		76
2022	2022		36	2022		36
2023	2023		33	2023		33
2024				2024		34
Thereafter	Thereafter		129	Thereafter		96
	Total	$	499	Total	$	385

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

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

		Oil	Natural Gas
		(MMBbl)	(MMcf)

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

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

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

~~Operating leases.~~Leases. The Company leases ~~vehicles,~~office space, office equipment, drilling rigs, field equipment and ~~office facilities under non-cancellable operating leases. Lease payments associated~~vehicles. Leases with ~~these operating leases were approximately $3 million and $2 million~~an initial term of 12 months or less are not recorded on the consolidated balance sheet. The Company elected a practical expedient to not separate non-lease components from lease components for the ~~three months ended September 30, 2018~~following asset types: office space, office equipment, drilling rigs, and ~~2017, respectively, and approximately $9 million and $7 million~~field equipment. The Company did not elect this practical expedient for ~~the nine months ended~~ ~~September 30, 2018~~ ~~and 2017, respectively.~~vehicle leases.

~~Future minimum lease commitments under non-cancellable operating~~The following table provides supplemental consolidated balance sheet information related to leases at ~~September 30, 2018~~ ~~were as follows:~~March 31, 2019:

(in millions)

Remaining 2018

$
3
2019

13
2020

12
2021

9
2022

2
2023

-
Thereafter

1

Total
$
40


(in millions)		Classification	March 31, 2019

Assets
Operating lease right-of-use assets		Other property and equipment, net	$	18
Finance lease right-of-use assets		Other property and equipment, net		15
Total lease right-of-use assets (a)			$	33

Liabilities
Current:
Operating		Other current liabilities	$	7
Finance		Other current liabilities		6
Noncurrent:
Operating		Asset retirement obligations and other long-term liabilities		13
Finance		Asset retirement obligations and other long-term liabilities		10
Total lease liabilities (a)			$	36


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

2521

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30,~~March 31, 2019

Unaudited

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


			Three Months Ended
(in millions)		Classification	March 31, 2019

Operating lease cost		General and administrative	$	2
Finance lease cost		Depreciation, depletion, and amortization (a)		2
Total lease cost			$	4


(a)	Interest on lease liabilities related to finance leases was immaterial during the three months ended March 31, 2019.

The Company’s short-term leases are comprised primarily of drilling rigs and certain field equipment. During the three months ended March 31, 2019, the Company’s gross lease cost related to its short-term leases was $94 million, of which $67 million was capitalized as part of oil and natural gas properties. A portion of these costs was reimbursed to the Company by other working interest owners.

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


		Three Months Ended
(in millions)		March 31, 2019

Cash paid for amounts included in measurement of lease liabilities:
Operating cash flows from operating leases	$	2
Financing cash flows from finance leases	$	2
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	-
Finance leases	$	3

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


	March 31, 2019

Weighted average remaining lease term (years):
Operating leases		3.5
Finance leases		2.9

Weighted average discount rate:
Operating leases		4.9%
Finance leases		4.4%

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

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


(in millions)		Operating Leases		Finance Leases

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

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

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


(in millions)

2019		$	14
2020			12
2021			10
2022			3
2023			-
Thereafter			1
	Total	$	40

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited

Note ~~11.~~10. Income taxes

The Company’s provision for income taxes ~~for the nine months ended September 30, 2018 and 2017~~ is based on the estimated annual effective tax rate plus discrete items. ~~The effective income tax rates were 26 percent and 37 percent for~~For the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017, respectively, and 23 percent and 37 percent for the nine months ended~~ ~~September 30, 2018~~ ~~and 2017, respectively.~~

The change in the Company’s effective tax rates for the three and nine months ended September 30, 2018 and 2017 is primarily due to (i) the reduction of the U.S. federal statutory corporate income tax rate from 35 percent to 21 percent, (ii) the impact of changes in non-deductible expenses, including transaction costs incurred in connection with the RSP Acquisition, and (iii) state income taxes, net of federal income tax benefits. As a result of the RSP Acquisition described in Note 4 and below, the Company recorded an income tax benefit of approximately $7$194 million and an income tax expense of approximately $254 million, respectively. The change is primarily due to the pre-tax loss for the three months ended March 31, 2019 as compared to the pre-tax income for the three months ended March 31, 2018.

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

The difference between the Company’s effective tax rates for the three months ended March 31, 2019 as compared to 2018 is primarily due to the research and development credit, net of ~~federal benefit, due to a change in~~unrecognized tax benefits, partially offset by the ~~Company’s estimated state tax rate. Additionally, the~~impact of other items. The Company recorded a discrete income tax benefit related to stock-based awards of approximately ~~$3 million and $6~~$2 million for each of the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017, respectively.~~2018.

On July 19, 2018, the Company completed the acquisition of RSP Permian Inc. 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. The Company recorded an opening balance sheet deferred tax liability of $518 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 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. ~~As part of the RSP Acquisition,~~At December 31, 2018, the Company ~~recorded an~~had cumulative unrecognized tax ~~benefit~~benefits of approximately ~~$20~~$63 million, primarily related to research and development credits. As of March 31, 2019, the Company estimated an increase in cumulative unrecognized tax benefits for the 2019 tax year of approximately $16 million. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period recognized. The timing as to when the Company will substantially resolve the uncertainties associated with the unrecognized tax benefit is ~~uncertain.~~

On December 22, 2017, the President of the United States signed into law the “Tax Cuts and Jobs Act” (“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 Staff Accounting Bulletin No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” (“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 September 30, 2018,~~ uncertainthe Company has not completed its accounting for all of the tax effects of the TCJA and has not made an adjustment to the provisional tax benefit recorded under SAB 118 at December 31, 2017. The Company has not finalized its accounting for the TCJA pending guidance on matters related to treatment of certain compensation and the completion of its re-measurement of certain deferred tax assets and liabilities. In addition, the Company has considered in its estimated annual effective tax rate for 2018 the impact of the statutory changes enacted by the TCJA, including reasonable estimates of those provisions effective for the 2018 tax year..

Note ~~12.~~11. Related party transactions

The Company paid royalties on certain properties to a partnership in which a director of the Company is the general partner and owns a 3.5 percent partnership interest. ~~These payments were reported~~

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

The payments to the Company’s ~~consolidated statements of operations and~~related parties totaled approximately $2$6 million and $1 million for the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017, respectively, and approximately $6 million and $5 million for the nine months ended September 30, 2018 and 2017,~~ respectively.

2624

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

Note ~~13.~~12. Earnings per share

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

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

The following table reconciles the Company’s earnings (loss) from operations and earnings (loss) attributable to common stockholders to the basic and diluted earnings (loss) used to determine the Company’s earnings (loss) per share amounts for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively, under the two-class method:



				Three Months Ended				Nine Months Ended					Three Months Ended
			September 30,				September 30,						March 31,
(in millions)	(in millions)		2018		2017		2018		2017		(in millions)		2019		2018

Net income (loss) as reported	Net income (loss) as reported		$	(199)	$	(113)	$	773	$	689	Net income (loss) as reported		$	(695)	$	835
Participating basic earnings (a)	Participating basic earnings (a)			-		-		(6)		(5)	Participating basic earnings (a)			-		(6)
	Basic earnings attributable to common stockholders			(199)		(113)		767		684	Basic earnings (loss) attributable to common stockholders			(695)		829
Reallocation of participating earnings	Reallocation of participating earnings			-		-		-		-	Reallocation of participating earnings			-		-
	Diluted earnings attributable to common stockholders		$	(199)	$	(113)	$	767	$	684	Diluted earnings (loss) attributable to common stockholders		$	(695)	$	829


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

2725

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three ~~and nine~~ months ended ~~September 30, 2018~~March 31, 2019 and ~~2017:~~2018:



			Three Months Ended		Nine Months Ended				Three Months Ended
			September 30,		September 30,				March 31,
(in thousands)	(in thousands)		2018	2017	2018	2017	(in thousands)		2019	2018

*Weighted average common shares outstanding:*	*Weighted average common shares outstanding:*						*Weighted average common shares outstanding:*
	Basic		188,953	147,557	161,605	147,233	Basic		199,148	147,925
		Dilutive common stock options	-	-	-	4		Dilutive performance units	-	537
		Dilutive performance units	313	-	342	549	Diluted		199,148	148,462
	Diluted		189,266	147,557	161,947	147,786

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

Three Months Ended

Nine Months Ended

Three Months Ended

September 30,

March 31,

(in thousands)

2018

2017

2018

2017

(in thousands)

2019

2018

Number of antidilutive units:

Antidilutive performance units

111

110

107

Performance units

324

Performance unit awards. The number of shares of common stock that will ultimately be issued for performance units will be determined by a combination of (i) comparing the Company’s total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. The performance period ~~is 36 months.~~on these awards can range from three to five years. The actual payout of shares will be between zero and 300 percent. See Note 5 for additional information on performance unit awards.

2826

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

Note ~~14.~~13. Subsidiary guarantors

At ~~September 30, 2018,~~March 31, 2019, certain of the Company’s 100 percent owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be released in certain customary circumstances including (i) in connection with any sale, exchange or other disposition, whether by merger, consolidation or otherwise, of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Company to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee.

See Note 98 for a summary of the Company’s senior notes. In accordance with practices accepted by the ~~U.S. Securities and Exchange Commission,~~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, ~~one~~certain of the Company’s subsidiaries ~~does~~do not guarantee the Company’s senior notes and isare included in the Company’s consolidated financial statements. ~~This entity is a~~These entities are 100 percent owned ~~subsidiary that was recently acquired,~~subsidiaries and isare referred to as a “Subsidiary Non-Guarantor” in the tables below. ~~An additional entity did~~The Company’s less than 100 percent owned subsidiaries, primarily equity method investments, do 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 the nine months ended September 30, 2018, the Reverse 1031 Exchange 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.notes.

The following condensed consolidating balance sheets at ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017~~2018, condensed consolidating statements of operations for the ~~three and~~ ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ and condensed consolidating statements of cash flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ 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.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited


Condensed Consolidating Balance Sheet
March 31, 2019


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

ASSETS
Accounts receivable - related parties		$	18,518	$	-	$	-	$	(18,518)	$	-
Other current assets			6		1,021		-		-		1,027
Oil and natural gas properties, net			-		22,405		16		-		22,421
Property and equipment, net			-		350		-		-		350
Investment in subsidiaries			5,629		-		-		(5,629)		-
Goodwill			-		2,229		-		-		2,229
Other long-term assets			15		126		-		-		141
	Total assets	$	24,168	$	26,131	$	16	$	(24,147)	$	26,168

LIABILITIES AND EQUITY
Accounts payable - related parties		$	-	$	18,502	$	16	$	(18,518)	$	-
Other current liabilities			368		1,292		-		-		1,660
Long-term debt			4,567		-		-		-		4,567
Other long-term liabilities			1,174		708		-		-		1,882
Equity			18,059		5,629		-		(5,629)		18,059
	Total liabilities and equity	$	24,168	$	26,131	$	16	$	(24,147)	$	26,168

Condensed Consolidating Balance Sheet
December 31, 2018


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

ASSETS
Accounts receivable - related parties		$	18,155	$	-	$	-	$	(18,155)	$	-
Other current assets			534		875		-		-		1,409
Oil and natural gas properties, net			-		21,988		17		-		22,005
Property and equipment, net			-		308		-		-		308
Investment in subsidiaries			5,411		-		-		(5,411)		-
Goodwill			-		2,224		-		-		2,224
Other long-term assets			224		124		-		-		348
	Total assets	$	24,324	$	25,519	$	17	$	(23,566)	$	26,294

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

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2019

Unaudited


Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2019


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

Total operating revenues		$	-	$	1,104	$	-	$	-	$	1,104
Total operating costs and expenses			(1,060)		(890)		-		-		(1,950)
	Income (loss) from operations		(1,060)		214		-		-		(846)
Interest expense			(47)		-		-		-		(47)
Other, net			218		4		-		(218)		4
	Income (loss) before income taxes		(889)		218		-		(218)		(889)
Income tax benefit			194		-		-		-		194
	Net income (loss)	$	(695)	$	218	$	-	$	(218)	$	(695)

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2018


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

Total operating revenues		$	-	$	942	$	5	$	-	$	947
Total operating costs and expenses			(34)		105		(3)		-		68
	Income (loss) from operations		(34)		1,047		2		-		1,015
Interest expense			(30)		-		-		-		(30)
Other, net			1,153		104		-		(1,153)		104
	Income before income taxes		1,089		1,151		2		(1,153)		1,089
Income tax expense			(254)		-		-		-		(254)
	Net income	$	835	$	1,151	$	2	$	(1,153)	$	835

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

Condensed Consolidating Balance Sheet
September 30, 2018

Parent

Subsidiary

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors
Non-Guarantor

Entries


Total

ASSETS








Accounts receivable - related parties

$
9,981

$
(8,190)

$
-

$
(1,791)

$
-
Other current assets


21

1,007

-

-

1,028
Oil and natural gas properties, net


-

21,601

17

-

21,618
Property and equipment, net


-

277

-

-

277
Investment in subsidiaries


5,097

-

-

(5,097)

-
Goodwill

-

2,246

-

-

2,246
Other long-term assets


17

24

-

-

41

Total assets

$
15,116

$
16,965

$
17

$
(6,888)

$
25,210









LIABILITIES AND EQUITY







Accounts payable - related parties

$
(8,190)

$
9,964

$
17

$
(1,791)

$
-
Other current liabilities


657

1,219

-

-

1,876
Long-term debt


4,143

-

-

-

4,143
Other long-term liabilities


1,274

685

-

-

1,959
Equity


17,232

5,097

-

(5,097)

17,232

Total liabilities and equity

$
15,116

$
16,965

$
17

$
(6,888)

$
25,210

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2019


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

Net cash flows provided by (used in) operating activities		$	(335)	$	958		$	-	$	-	$	623
Net cash flows used in investing activities			-		(902)			-		-		(902)
Net cash flows provided by (used in) financing activities			335		(56)			-		-		279
	Net increase in cash and cash equivalents		-		-			-		-		-
	Cash and cash equivalents at beginning of period		-		-			-		-		-
	Cash and cash equivalents at end of period	$	-	$	-		$	-	$	-	$	-

Condensed Consolidating 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 Cash Flows
Three Months Ended March 31, 2018


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

Net cash flows provided by operating activities		$	351	$	137		$	-	$	-	$	488
Net cash flows used in investing activities			-		(93)			-		-		(93)
Net cash flows used in financing activities			(351)		(44)			-		-		(395)
	Net increase in cash and cash equivalents		-		-			-		-		-
	Cash and cash equivalents at beginning of period		-		-			-		-		-
	Cash and cash equivalents at end of period	$	-	$	-		$	-	$	-	$	-

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~March 31, 2019

Unaudited

Note 14. Subsequent events

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

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

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

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

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2018

Parent

Subsidiary

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors

Non-Guarantor

Entries


Total



Total operating revenues

$
-

$
1,192

$
-

$
-

$
1,192
Total operating costs and expenses


(626)

(791)

-

-

(1,417)

Income (loss) from operations


(626)

401

-

-

(225)
Interest expense


(46)

-

-

-

(46)
Other, net


404

3

-

(404)

3

Income (loss) before income taxes


(268)

404

-

(404)

(268)
Income tax benefit


69

-

-

-

69

Net income (loss)

$
(199)

$
404

$
-

$
(404)

$
(199)


				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total

Oil Price Swaps: (a)
	*2019:*
		Volume (Bbl)		-		1,707,000		1,451,000		1,281,000		4,439,000
		Price per Bbl	$	-	$	62.64	$	63.14	$	63.43	$	63.03
	*2021:*
		Volume (Bbl)		1,170,000		1,183,000		1,196,000		1,196,000		4,745,000
		Price per Bbl	$	56.72	$	56.72	$	56.72	$	56.72	$	56.72
Oil Basis Swaps: (b)
	*2019:*
		Volume (Bbl)		-		-		92,000		920,000		1,012,000
		Price per Bbl	$	-	$	-	$	(1.05)	$	(0.07)	$	(0.16)
	*2020:*
		Volume (Bbl)		1,092,000		-		-		-		1,092,000
		Price per Bbl	$	0.10	$	-	$	-	$	-	$	0.10
	*2021:*
		Volume (Bbl)		540,000		546,000		552,000		552,000		2,190,000
		Price per Bbl	$	0.50	$	0.50	$	0.50	$	0.50	$	0.50


(a)	The oil derivative contracts are settled based on the NYMEX – WTI calendar-month average futures price.
(b)	The basis differential price is between Midland – WTI and Cushing – WTI. These contracts are settled on a calendar-month basis.
(b)

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2017

Parent

Subsidiary

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors

Non-Guarantors

Entries


Total



Total operating revenues

$
-

$
619

$
8

$
-

$
627
Total operating costs and expenses


(207)

(491)

(6)

-

(704)

Income (loss) from operations


(207)

128

2

-

(77)
Interest expense


(39)

-

-

-

(39)
Loss on extinguishment of debt

(65)

-

-

-

(65)
Other, net


132

2

-

(132)

2

Income (loss) before income taxes


(179)

130

2

(132)

(179)
Income tax benefit


66

-

-

-

66

Net income (loss)

$
(113)

$
130

$
2

$
(132)

$
(113)

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2018~~

~~Unaudited~~

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2018

Parent

Subsidiary

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors

Non-Guarantor

Entries


Total



Total operating revenues

$
-

$
3,079

$
5

$
-

$
3,084
Total operating costs and expenses


(794)

(1,294)

(3)

-

(2,091)

Income (loss) from operations


(794)

1,785

2

-

993
Interest expense


(103)

-

-

-

(103)
Other, net


1,895

108

-

(1,895)

108

Income before income taxes


998

1,893

2

(1,895)

998
Income tax expense


(225)

-

-

-

(225)

Net income

$
773

$
1,893

$
2

$
(1,895)

$
773

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2017

Parent

Subsidiary

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors

Non-Guarantors

Entries


Total



Total operating revenues

$
-

$
1,798

$
8

$
-

$
1,806
Total operating costs and expenses


288

(837)

(6)

-

(555)

Income from operations


288

961

2

-

1,251
Interest expense


(117)

(1)

-

-

(118)
Loss on extinguishment of debt


(66)

-

-

-

(66)
Other, net


982

20

-

(982)

20

Income before income taxes


1,087

980

2

(982)

1,087
Income tax expense


(398)

-

-

-

(398)

Net income

$
689

$
980

$
2

$
(982)

$
689

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2018~~

~~Unaudited~~

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2018

Parent

Subsidiary
Subsidiary
Consolidating

(in millions)


Issuer

Guarantors
Non-Guarantor

Entries


Total



Net cash flows provided by operating activities

$
386

$
1,475

$
-

$
-

$
1,861
Net cash flows used in investing activities

-

(1,422)

-

-

(1,422)
Net cash flows used in financing activities


(386)

(29)

-

-

(415)

Net increase in cash and cash equivalents

-

24

-

-

24

Cash and cash equivalents at beginning of period
-

-

-

-

-

Cash and cash equivalents at end of period

$
-

$
24

$
-

$
-

$
24

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2017

Parent

Subsidiary

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors

Non-Guarantors

Entries


Total



Net cash flows provided by operating activities

$
99

$
1,084

$
2

$
-

$
1,185
Net cash flows used in investing activities


-

(592)

(615)

-


(1,207)
Net cash flows provided by (used in) financing


activities

(99)

(545)

613

-

(31)

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

$
-

$
-

$
-

$
-

$
-

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2018~~

~~Unaudited~~

~~Note 15.~~ ~~Subsequent events~~

~~New commodity derivative contracts.~~~~After September 30, 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)

720,000

546,000

552,000

552,000

2,370,000

Price per Bbl
$
67.15
$
67.11
$
67.11
$
67.11
$
67.12

2020:

Volume (Bbl)

455,000

455,000

368,000

368,000

1,646,000

Price per Bbl
$
64.37
$
64.37
$
64.18
$
64.18
$
64.28

(a)
The oil derivative contracts are settled based on the NYMEX – WTI monthly average futures price.

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2018~~March 31, 2019

Unaudited

Note ~~16.~~15. Supplementary information

Capitalized costs


			September 30,		December 31,					March 31,		December 31,
(in millions)	(in millions)		2018		2017			(in millions)		2019		2018

*Oil and natural gas properties:*	*Oil and natural gas properties:*							*Oil and natural gas properties:*
	Proved		$	24,361	$	18,565		Proved		$	26,000	$	24,992
	Unproved			6,619		2,702		Unproved			6,559		6,714
	Less: accumulated depletion			(9,362)		(8,460)		Less: accumulated depletion			(10,138)		(9,701)
		Net capitalized costs for oil and natural gas properties	$	21,618	$	12,807	(a)		Net capitalized costs for oil and natural gas properties	$	22,421	$	22,005


(a)	Approximately $135 million of the balance at December 31, 2017 relates to assets held for sale that were disposed of
	during January 2018.

Costs incurred for oil and natural gas producing activities



		Three Months Ended				Nine Months Ended					Three Months Ended
		September 30,				September 30,					March 31,
(in millions)	(in millions)	2018		2017		2018		2017		(in millions)	2019		2018

Property acquisition costs:	Property acquisition costs:									*Property acquisition costs:*
	Proved	$	4,126	$	162	$	4,126	$	301	Proved	$	-	$	-
	Unproved		3,578		472		3,596		865	Unproved		4		13
Exploration	Exploration		481		252		1,059		725	Exploration		462		243
Development	Development		280		175		653		478	Development		464		207
	Total costs incurred for oil and natural gas properties	$	8,465	$	1,061	$	9,434	$	2,369	Total costs incurred for oil and natural gas properties	$	930	$	463

3532

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

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

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

Overview

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

Financial and Operating Performance

On July 19, 2018, we completed our acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”), which, among other things, impacted the comparability of our results of operations. Our financial and operating performance for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ included the following highlights:

· Net ~~income~~loss was $~~773~~695 million ($~~4.74~~(3.49) per diluted share) as compared to ~~$689~~net income of $835 million ($~~4.63~~5.58 per diluted share) for the first ~~nine~~three months of ~~2018~~2019 and ~~2017,~~2018, respectively. The ~~increase~~decrease in net income was primarily due to:

• $~~$1.3 billion~~1,024 million increase in ~~oil and natural gas revenues~~loss on derivatives due to a $1,059 million loss on derivatives during the three months ended March 31, 2019, as compared to a ~~result~~loss of a$35 million 33~~percent increase in production and a 28 percent increase in commodity price realizations per Boe~~ ~~(excluding the effects of derivative activities);~~during 2018;

• $~~173~~722 million net decrease in ~~our income tax provision~~gain on disposition of assets related to a gain of approximately $723 million, primarily due to ~~the lower U.S. federal statutory corporate income tax rate~~certain acquisitions and divestitures during 2018, as ~~a result~~discussed in Note 4 of the ~~Tax Cuts and Jobs Act (the “TCJA”) for the nine months ended September 30, 2018, as compared~~Condensed Notes to ~~2017;~~Consolidated Financial Statements;

• $88148 million increase in depreciation, depletion and amortization expense, primarily due to an increase in production and the depletion rate per Boe;

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

• $52 million net increase in gain on disposition of assets due to a gain of approximately $719 million during the nine months ended September 30, 2018 primarily due to our February 2018 acquisition and divestiture and Southern Delaware Basin divestitures, as compared to a gain of approximately $667 million during 2017 primarily due to our disposition of Alpha Crude Connector, LLC (“ACC”);

~~partially offset by:~~

•$~~1.1~~ ~~billion change in (gain) loss on derivatives due to a $793 million loss on derivatives~~ ~~during the nine months ended September 30, 2018, as compared to a~~ ~~$289 million gain~~ ~~during 2017;~~

•~~$185 million increase in depreciation, depletion and amortization expense, primarily due to an increase in production, partially offset by a lower depletion rate per Boe;~~

•~~$123~~44 million increase in production expense, primarily due to ~~(i)~~ increased production and activities associated with the additional wells successfully drilled and completed in ~~2017~~2018 and ~~2018, (ii)~~2019 as well as our acquisitions ~~and nonmonetary transactions~~ during ~~the fourth quarter of 2017 and first nine months of 2018, (iii) increased cost of services and (iv) increased workover costs;~~2018;

partially offset by:

• $89157 million increase in ~~production~~oil and ~~ad valorem tax expense, primarily due to increased production taxes~~natural gas revenues as a result of ~~increased oil and natural gas sales; and~~a 44percent increase in production, partially offset by a 19 percent decrease in commodity price realizations per Boe (excluding the effects of derivative activities).

•~~$37 million increase in transaction costs, primarily due to consulting, investment banking, advisory, legal and other fees related to the RSP Acquisition.~~

· Average daily sales volumes of ~~248~~328 MBoe per day during the first ~~nine~~three months of ~~2018~~2019 increased 3344 percent as compared to ~~186~~228 MBoe per day during ~~2017.~~2018.

· Net cash provided by operating activities increased by approximately ~~$676~~$135 million to ~~$1,861~~$623 million for the first ~~nine~~three months of ~~2018,~~2019, as compared to ~~$1,185~~$488 million in the first ~~nine~~three months of ~~2017,~~2018, primarily due to an increase in oil and natural gas revenues ~~partially offset by (i)~~and changes related to cash settlements on derivatives, ~~(ii)~~partially offset by increased ~~production expense~~operating costs on our oil and ~~(iii) increased production tax expense.~~natural gas properties.

Commodity Prices

Our results of operations are heavily influenced by commodity prices. Commodity prices may fluctuate widely in response to (i) relatively minor changes in the supply of and demand for oil ~~natural gas~~ and natural gas, ~~liquids,~~ (ii) market uncertainty and (iii) a variety of additional factors that are beyond our control. Factors that may impact future commodity prices, including the price of oil ~~natural gas~~ and natural gas, ~~liquids,~~ include but are not limited to:

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

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

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

· the U.S. economy,

· weather conditions, and

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

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

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

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

·the quality of the oil we produce;

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

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

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

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

· technological advances affecting energy consumption and energy supply;

· the effect of energy conservation efforts;

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

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

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

· the ~~quality of the oil we produce;~~

·~~the price and availability of alternative fuels; and~~

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

·the price, availability and acceptance of alternative fuels.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the

geographic region of the production. From time to time, we may ~~economically~~ hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Notes 87 and 1514 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commodity

derivative positions at ~~September 30, 2018~~March 31, 2019 and additional derivative contracts entered into subsequent to ~~September 30, 2018,~~March 31, 2019, respectively.

~~Oil and natural gas prices have been subject to significant fluctuations during~~The following table sets forth the ~~past several years. The~~ average New York Mercantile Exchange (“NYMEX”) oil ~~price was higher and the average NYMEX natural gas price was lower during the comparable periods of 2018 measured against 2017. The following table sets forth the average NYMEX oil~~ and natural gas prices for the three ~~and nine~~ months ended ~~September 30, 2018~~March 31, 2019 and ~~2017,~~2018, as well as the high and low NYMEX prices for the same periods:



			Three Months Ended				Nine Months Ended						Three Months Ended
			September 30,				September 30,						March 31,
			2018		2017		2018		2017				2019		2018

Average NYMEX prices:	Average NYMEX prices:										Average NYMEX prices:
	Oil (Bbl)		$	69.60	$	48.12	$	66.83	$	49.45	Oil (Bbl)		$	54.87	$	62.96
	Natural gas (MMBtu)		$	2.87	$	2.95	$	2.85	$	3.06	Natural gas (MMBtu)		$	2.88	$	2.84

High and Low NYMEX prices:	High and Low NYMEX prices:										High and Low NYMEX prices:
	*Oil (Bbl):*										*Oil (Bbl):*
		High	$	74.15	$	52.22	$	74.15	$	54.45		High	$	60.14	$	66.14
		Low	$	65.01	$	44.23	$	59.19	$	42.53		Low	$	45.41	$	59.19
	*Natural gas (MMBtu):*										*Natural gas (MMBtu):*
		High	$	3.08	$	3.15	$	3.63	$	3.72		High	$	3.59	$	3.63
		Low	$	2.72	$	2.77	$	2.55	$	2.56		Low	$	2.55	$	2.55

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of ~~$76.41~~$66.30 and ~~$66.43~~$61.59 per Bbl and ~~$3.32~~$2.71 and ~~$3.09~~$2.46 per MMBtu, respectively, during the period from ~~October~~April 1, ~~2018~~2019 to ~~October~~April 29, ~~2018.~~2019. At ~~October~~April 29, ~~2018,~~2019, the NYMEX oil price and NYMEX natural gas price were ~~$67.04~~$63.50 per Bbl and ~~$3.19~~$2.59 per MMBtu, respectively.

Historically, and during the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, we derived a significant portion of our total natural gas revenues from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues, our realized natural gas price (excluding the effects of derivatives) reflected a price greater than the related NYMEX natural gas price for the three and nine months ended September 30, 2018. The average Mont Belvieu price for a blended barrel of natural gas liquids was ~~$34.82~~$24.13 per Bbl and ~~$25.04~~$27.64 per Bbl during the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017, respectively, and $30.73 per Bbl and $23.74 per Bbl during the nine months ended September 30, 2018 and 2017,~~ respectively.

3835

Recent Events

~~2019 capital budget and dividends.~~ In October 2018, our board approved the 2019 capital budget of up to $3.8 billion. We expect our 2019 capital spending on drilling and completion activity to range between $3.4 billion and $3.6 billion. Additionally, subject to declaration by our board, we plan to initiate a quarterly dividend of $0.125 per share beginning in the first quarter of 2019, with an indicated annual rate of $0.50 per share.

~~RSP Acquisition.~~ Oryx divestiture.~~On July 19, 2018, we completed~~In April 2019, Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering and transportation system in the ~~RSP Acquisition. Under~~Delaware Basin, entered into an agreement to sell 100 percent of its equity interests. We expect to receive approximately $300 million, net of closing costs, for our 23.75 percent membership interest. We intend to use the 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 our common stock. We issued approximately 51 million shares of common stock at a price of $148.27 per share, resulting in total consideration paid to the former RSP shareholders of approximately $7.5 billion. Refer to Note 4 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding the acquisition.

~~Long-term debt.~~ On July 2, 2018, we 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 net proceeds of ~~approximately $1,579 million were used~~this sale 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”) and to repay ~~a portion of the outstanding indebtedness under RSP’s existing credit facility. We repaid the remaining balance under RSP’s credit facility with~~ borrowings under our credit facility, as amended and restated ~~(our “Credit~~(“Credit Facility”)~~, resulting in a total payoff of $1,773 million, which included the accrued interest and premiums on the senior notes and other fees and expenses related to RSP’s credit facility.~~.

~~2018 capital budget.~~ Midstream joint venture.In ~~July 2018,~~April 2019, we entered into a midstream joint venture, Beta Holding Company, LLC (“Beta Holding”), to construct a pipeline to gather and transport oil production in the northern portion of the Midland Basin. We also entered into a ten-year dedication agreement with an affiliate of Beta Holding to transport our oil production in the northern portion of the Midland Basin.

2019 dividends. On February 19, 2019, our board of directors declared a cash dividend of $0.125 per share. The total cash dividend, including the cash dividend paid on unvested restricted stock awards, of $25 million was paid on March 29, 2019 to stockholders of record as of March 1, 2019. On April 30, 2019, our board of directors approved a ~~revised 2018 capital budget~~cash dividend of ~~up to $2.7 billion. The revised budget includes capital we plan to invest during~~$0.125 per share for the second ~~half~~quarter of the year on the acquired RSP assets. We expect our 2018 capital spending on drilling and completion activity to range between $2.5 billion and $2.6 billion. Our 2018 capital budget, excluding acquisitions and based on our current expectations of commodity prices and costs,2019 that is expected to be ~~within our operating cash flows.~~paid on June 28, 2019 to stockholders of record as of May 10, 2019.

Derivative Financial Instruments

Derivative financial instrument exposure. At ~~September 30, 2018,~~March 31, 2019, the fair value of our financial derivatives was a net liability of ~~$910~~$364 million. Under the terms of our financial derivative instruments, we do not have exposure to potential “margin calls” on our financial derivative instruments. The terms of our Credit Facility do not allow us to offset amounts we may owe a lender against amounts we may be owed related to our derivative financial instruments with such party.

New commodity derivative contracts. After ~~September 30, 2018,~~March 31, 2019, we entered into derivative contracts to hedge additional amounts of estimated future production. Refer to Note 1514 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding these commodity derivative contracts.

3936

Results of Operations

The following table sets forth summary information concerning our production and operating data for the three ~~and nine~~ months ended ~~September 30, 2018~~March 31, 2019 and ~~2017.~~2018. The actual historical data in this table excludes results from the RSP Acquisition for periods prior to July 19, 2018. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions and divestitures, the historical information presented below should not be interpreted as being indicative of future results.

Three Months Ended

Nine Months Ended



September 30,

September 30,

2018

2017

2018

2017

Production and operating data:

Net production volumes:

Oil (MBbl)


16,979

11,000

42,947

31,527

Natural gas (MMcf)


56,348

40,626

148,633

116,241

Total (MBoe)


26,370

17,771

67,719

50,901



Average daily production volumes:

Oil (Bbl)


184,554

119,565

157,315

115,484

Natural gas (Mcf)


612,478

441,587

544,443

425,791

Total (Boe)


286,634

193,163

248,056

186,449



Average prices per unit:


Oil, without derivatives (Bbl)

$
56.38

$
45.29

$
59.25

$
46.34

Oil, with derivatives (Bbl) (a)

$
53.67

$
47.81

$
53.55

$
50.45

Natural gas, without derivatives (Mcf)

$
4.18

$
3.18

$
3.63

$
2.96

Natural gas, with derivatives (Mcf) (a)

$
4.21

$
3.22

$
3.67

$
2.94

Total, without derivatives (Boe)

$
45.23

$
35.29

$
45.54

$
35.47

Total, with derivatives (Boe) (a)

$
43.56

$
36.96

$
42.02

$
37.95



Operating costs and expenses per Boe: (b)


Oil and natural gas production

$
5.93

$
5.99

$
6.15

$
5.76

Production and ad valorem taxes

$
3.37

$
2.70

$
3.38

$
2.75

Gathering, processing and transportation

$
0.60

$
-

$
0.53

$
-

Depreciation, depletion and amortization

$
15.43

$
16.00

$
15.27

$
16.66

General and administrative

$
3.13

$
3.60

$
3.26

$
3.56

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

Three Months Ended

Nine Months Ended




September 30,

September 30,

(in millions)

2018

2017

2018

2017

Net cash receipts from (payments on) derivatives:


Oil derivatives

$
(46)

$
28

$
(245)

$
129

Natural gas derivatives

2

2

7

(3)

Total

$
(44)

$
30

$
(238)

$
126

The presentation of average prices with derivatives is a result of including the net cash receipts from (payments on) commodity derivatives that are presented in our statements of cash flows. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community.

(b)
Per Boe amounts calculated using dollars and volumes rounded to thousands.


					Three Months Ended
					March 31,
					2019		2018

*Production and operating data:*
	Net production volumes:
		Oil (MBbl)				18,936		12,939
		Natural gas (MMcf)				63,769		45,448
		Total (MBoe)				29,564		20,514

	Average daily production volumes:
		Oil (Bbl)				210,400		143,767
		Natural gas (Mcf)				708,544		504,978
		Total (Boe)				328,491		227,930

	Average prices per unit:
		Oil, without derivatives (Bbl)			$	49.39	$	61.29
		Oil, with derivatives (Bbl) (a)			$	49.56	$	52.59
		Natural gas, without derivatives (Mcf)			$	2.64	$	3.39
		Natural gas, with derivatives (Mcf) (a)			$	2.59	$	3.41
		Total, without derivatives (Boe)			$	37.33	$	46.17
		Total, with derivatives (Boe) (a)			$	37.34	$	40.71

	Operating costs and expenses per Boe: (b)
		Oil and natural gas production			$	5.87	$	6.33
		Production and ad valorem taxes			$	2.92	$	3.40
		Gathering, processing and transportation			$	0.88	$	0.53
		Depreciation, depletion and amortization			$	15.74	$	15.43
		General and administrative			$	3.08	$	3.31


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


					Three Months Ended
					March 31,
		(in millions)			2019		2018

		Net cash receipts from (payments on) derivatives:
			Oil derivatives		$	3	$	(113)
			Natural gas derivatives			(3)		1
				Total	$	-	$	(112)


		The presentation of average prices with derivatives is a result of including the net cash receipts from (payments on) commodity derivatives that are presented in our consolidated statements of cash flows. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community.



	(b)	Per Boe amounts calculated using dollars and volumes rounded to thousands.
	(b)

4037

Three Months Ended ~~September 30, 2018~~March 31, 2019 Compared to Three Months Ended ~~September 30, 2017~~March 31, 2018

Oil and natural gas revenues. Revenue from oil and natural gas operations was $~~1,192~~1,104 million for the three months ended ~~September 30, 2018~~March 31, 2019, an increase of $~~565~~157 million ~~(90~~(17 percent) from ~~$627~~$947 million for ~~2017~~2018. This increase was primarily due to the increase in oil and natural gas production, ~~attributable~~in part due to an increase in non-operated revenues, partially offset by the ~~RSP Acquisition and wells successfully drilled and completed, as well as the increase~~decrease in realized oil and natural gas prices (excluding the effects of derivative activities). Additionally, on January 1, 2018, we adopted Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with Customers,” (“ASC 606”), which requires certain costs related to gathering, processing and transportation to be separately presented on the consolidated statements of operations. Prior to the adoption of ASC 606, these costs were generally accounted for as a deduction to revenue and included within total operating revenues on the consolidated statements of operations. We elected to use the modified retrospective approach for adopting ASC 606, and as such prior period amounts have not been restated. See Note 2 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding the adoption of ASC 606. Specific factors affecting oil and natural gas revenues include the following:

· total oil production was ~~16,979~~18,936 MBbl for the three months ended ~~September 30, 2018~~March 31, 2019, an increase of ~~5,979~~5,997 MBbl (5446 percent) from ~~11,000~~12,939 MBbl for ~~2017~~2018;

· average realized oil price (excluding the effects of derivative activities) was ~~$56.38~~$49.39 per Bbl during the three months ended ~~September 30, 2018~~March 31, 2019, ~~an increase~~a decrease of 2419 percent from $~~45.29~~61.29 per Bbl during ~~2017~~2018. For the three months ended ~~September 30, 2018,~~March 31, 2019, our crude oil price differential relative to NYMEX was ~~$(13.22)~~$(5.48) per Bbl, or a realization of approximately 8190 percent, as compared to a crude oil price differential relative to NYMEX of ~~$(2.83)~~$(1.67) per Bbl, or a realization of approximately 9497 percent, for ~~2017.~~2018. The basis differential (referred to as the “Mid-Cush differential”) between the location of Midland, Texas and Cushing, Oklahoma ~~(NYMEX pricing location)~~(settlement location for NYMEX pricing) for our oil directly impacts our realized oil price. For the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ the average market Mid-Cush ~~differentials were~~differential was a price ~~reductions~~reduction of $~~(12.66)~~3.86 per Bbl and a price benefit of $~~(0.75)~~0.38 per Bbl, respectively. ~~Our crude oil price differential relative to NYMEX excluding the~~The Mid-Cush differential ~~was $(0.56) per Bbl for~~significantly narrowed in March 2019 and into the ~~three months ended~~ ~~September 30, 2018, as compared to $(2.08) per Bbl for~~second quarter of 2019, although it is possible that the ~~three months ended~~ ~~September 30, 2017. This difference was due to the fluctuation between the price we receive, which is based on a calendar month average, as compared to NYMEX~~; differential could widen again at certain times during 2019;

· total natural gas production was ~~56,348~~63,769 MMcf for the three months ended ~~September 30, 2018~~March 31, 2019, an increase of ~~15,722~~18,321 MMcf (3940 percent) from ~~40,626~~45,448 MMcf for ~~2017~~2018; and

· average realized natural gas price (excluding the effects of derivative activities) was ~~$4.18~~$2.64 per Mcf during the three months ended ~~September 30, 2018~~March 31, 2019, ~~an increase~~a decrease of 3122 percent from ~~$3.18~~$3.39 per Mcf during ~~2017.~~2018. For the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ we realized approximately ~~146~~92 percent and ~~108~~119 percent, respectively, of the average NYMEX natural gas prices for the respective periods. ~~Historically, and during the~~ ~~three months ended~~ ~~September 30, 2018, we derived~~We derive a significant portion of our total natural gas revenues from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues, our realized natural gas price (excluding the effects of derivatives) historically reflected a price greater than the related NYMEX natural gas price. However, during the latter part of 2018 and into 2019, amid concerns of rising natural gas production relative to natural gas takeaway in the Permian Basin, the price differential for ~~the~~ ~~three months ended~~ ~~September 30, 2018. The~~natural gas residue increased significantly, and could increase inagain at certain times during 2019. These widening natural gas residue differentials negatively impacted our realized natural gas ~~price (excluding the effects of derivatives) as a percentage of NYMEX~~prices during the three months ended ~~September 30, 2018 as compared to 2017 was primarily due to an increase~~March 31, 2019, but were partially offset by the value of the natural gas liquids. The combination of these factors resulted in a realized natural gas price of 92 percent of the average NYMEX natural gas price, which falls below our historical amounts. In addition, the average Mont Belvieu price for a blended barrel of natural gas liquids ~~which was $34.82 per Bbl and $25.04~~decreased from $27.64 per Bbl during the three months ended ~~September 30,~~ 2018 ~~and 2017, respectively. The increase in our realized natural gas price was also due~~ to $24.13 per Bbl during the ~~adoption of ASC 606, as our natural gas realized price was $0.15 per Mcf higher than what it would have been under the previous revenue standard.~~three months ended March 31, 2019.

4138

Oil and natural gas production expenses. The following table provides the components of our oil and natural gas production expenses for the three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017:~~2018:


				Three Months Ended September 30,										Three Months Ended March 31,
				2018				2017						2019				2018
					Per				Per						Per				Per
(in millions, except per unit amounts)	(in millions, except per unit amounts)		Amount		Boe		Amount		Boe		(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Lease operating expenses	Lease operating expenses		$	146	$	5.54	$	100	$	5.68	Lease operating expenses		$	166	$	5.59	$	121	$	5.88
Workover costs	Workover costs			10		0.39		6		0.31	Workover costs			8		0.28		9		0.45
		Total oil and natural gas production expenses	$	156	$	5.93	$	106	$	5.99		Total oil and natural gas production expenses	$	174	$	5.87	$	130	$	6.33

Lease operating expenses were ~~$146~~$166 million ($~~5.54~~5.59 per Boe) for the three months ended ~~September 30, 2018~~March 31, 2019, which was an increase of ~~$46~~$45 million from ~~$100~~$121 million ($~~5.68~~5.88 per Boe) during ~~2017~~2018. The increase in lease operating expenses during the ~~third~~first quarter of ~~2018~~2019 as compared to ~~2017~~2018 was primarily ~~due to~~the result of (i) ~~increased production and activities associated with the RSP Acquisition and~~ additional wells successfully drilled and completed and (ii) ~~increased cost of services.~~our acquisitions during 2018, primarily the RSP Acquisition. The decrease in lease operating expenses per Boe was primarily due to increased ~~production, partially offset by the increase in lease operating expenses noted above.~~production.

Workover costs were ~~$10~~$8 million ($~~0.39~~0.28 per Boe) for the three months ended ~~September 30, 2018~~March 31, 2019, which was ~~an increase~~a decrease of $4$1 million from $6$9 million ($~~0.31~~0.45 per Boe) during ~~2017~~2018. The ~~increase~~decrease in workover costs during the ~~third~~first quarter of ~~2018~~2019 as compared to ~~2017~~2018 was primarily due to ~~increased~~decreased workover ~~activity and cost of services.~~activity. The ~~increase~~decrease in workover costs per Boe was primarily due to the ~~increase~~decrease in workover costs ~~noted above, partially offset by~~along with an increase in production.

Production and ad valorem taxes. The following table provides the components of our production and ad valorem tax expenses for the three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017:~~2018:


				Three Months Ended September 30,										Three Months Ended March 31,
				2018				2017						2019				2018
					Per				Per						Per				Per
(in millions, except per unit amounts)	(in millions, except per unit amounts)		Amount		Boe		Amount		Boe		(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Production taxes	Production taxes		$	79	$	2.98	$	44	$	2.48	Production taxes		$	70	$	2.38	$	64	$	3.13
Ad valorem taxes	Ad valorem taxes			10		0.39		4		0.22	Ad valorem taxes			16		0.54		6		0.27
		Total production and ad valorem taxes	$	89	$	3.37	$	48	$	2.70		Total production and ad valorem taxes	$	86	$	2.92	$	70	$	3.40

Production taxes per unit of production were ~~$2.98~~$2.38 per Boe during the three months ended ~~September 30, 2018~~March 31, 2019, ~~an increase~~a decrease of 2024 percent from ~~$2.48~~$3.13 per Boe during ~~2017~~2018. Over the same period, our revenue per Boe (excluding the effects of derivatives) ~~increased 28~~decreased 19 percent. The ~~increase~~decrease in production taxes per unit of production was ~~directly related~~due to ~~the increase in oil and natural gas sales, partially offset by~~lower realized revenue per Boe along with a higher percentage of our total production originating in Texas, which has a lower tax rate than New Mexico. Production taxes fluctuate with the market value of our production sold, while ad valorem taxes are generally based on the valuation of our oil and natural gas properties at the beginning of the year, which vary across the different areas in which we operate. Ad valorem taxes increased by $10 million primarily due to additional wells drilled and completed, new wells acquired in the RSP Acquisition and an increase in property values and tax rates in certain counties. The increase in ad valorem taxes per Boe was primarily due to an increase in property values and tax rates.

4239

Gathering, processing and transportation costs. The following table shows the gathering, processing and transportation costs for the three months ended ~~September 30, 2018~~March 31, 2019:

Three Months Ended

Three Months Ended March 31,

September 30, 2018

2019

2018

Per

(in millions, except per unit amounts)

Amount

Boe

(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

Gathering, processing and transportation costs

0.60

Gathering, processing and transportation costs

0.88

0.53

Gathering, processing and transportation costs were ~~$16~~$26 million ($~~0.60~~0.88 per Boe) for the three months ended ~~September 30, 2018~~March 31, 2019~~. On January 1, 2018, we adopted ASC 606, which requires certain amounts related to~~, an increase of 136 percent from $11 million ($0.53 per Boe) during 2018. The increase in gathering, processing and transportation costs was primarily due to ~~be separately presented on the consolidated statements of operations. Prior~~a certain crude oil gathering and transportation contract that, among other things, was modified to ~~the adoption of ASC 606, the majority of these~~allow repurchase rights. As such, costs related to this contract that were ~~accounted for~~previously recorded as a deduction to revenue during the three months ended March 31, 2018, are now recorded in gathering, processing and included within total operating revenues on the consolidated statements of operations. We have elected to use the modified retrospective approach for adopting ASC 606, and as such, prior period amounts have not been restated.transportation costs. In addition, ~~our~~contributing to the increase in gathering, processing and transportation costs ~~are impacted by production volumes~~was the RSP Acquisition and the increase in production. The increase in gathering, processing and transportation costs per Boe was primarily related to this crude oil gathering and transportation contract, fixed costs associated with certain ~~contracts.~~contracts and higher priced trucking services in certain areas.

Exploration and abandonments expense. The following table provides the components of our exploration and abandonments expense for the three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017:~~2018:


		Three Months Ended					Three Months Ended
		September 30,					March 31,
(in millions)	(in millions)	2018		2017		(in millions)	2019		2018

Geological and geophysical	Geological and geophysical	$	2	$	2	Geological and geophysical	$	6	$	5
Leasehold abandonments	Leasehold abandonments		6		-	Leasehold abandonments		30		10
Other	Other		2		5	Other		11		3
	Total exploration and abandonments	$	10	$	7	Total exploration and abandonments	$	47	$	18

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

For the three months ended ~~September 30,~~March 31, 2019 and 2018, we recorded approximately $6$30 million and $10 million, respectively, of leasehold abandonments, ~~which were~~ primarily related to certain expiring acreage ~~in the Northern Delaware Basin~~and acreage where we had no future plans to drill ~~and acres which expired~~located primarily in the ~~Southern~~ Delaware Basin.

Our other expense for the periods presented above primarily consists of surface and title costs on locations that we no longer intend to drill, certain plugging costs, delay rentals and ~~delay rentals.~~other exploratory well costs. The increase in other expense was primarily due to the abandonment of one exploratory well during the three months ended March 31, 2019 as a result of certain mechanical issues encountered during the completion of the well that made it unable to produce hydrocarbons.

4340

Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017:~~2018:


		Three Months Ended September 30,									Three Months Ended March 31,
		2018				2017					2019				2018
				Per				Per					Per				Per
(in millions, except per unit amounts)	(in millions, except per unit amounts)	Amount		Boe		Amount		Boe		(in millions, except per unit amounts)	Amount		Boe		Amount		Boe

Depletion of proved oil and natural gas properties	Depletion of proved oil and natural gas properties	$	401	$	15.19	$	279	$	15.67	Depletion of proved oil and natural gas properties	$	457	$	15.47	$	311	$	15.13
Depreciation of other property and equipment	Depreciation of other property and equipment		5		0.20		5		0.31	Depreciation of other property and equipment		7		0.24		5		0.26
Amortization of intangible assets	Amortization of intangible assets		-		0.04		-		0.02	Amortization of intangible assets		1		0.03		1		0.04
	Total depletion, depreciation and amortization	$	406	$	15.43	$	284	$	16.00	Total depletion, depreciation and amortization	$	465	$	15.74	$	317	$	15.43

Oil price used to estimate proved oil reserves at period end	Oil price used to estimate proved oil reserves at period end	$	59.92			$	46.27			Oil price used to estimate proved oil reserves at period end	$	59.52			$	49.94
Natural gas price used to estimate proved natural gas reserves at period end	Natural gas price used to estimate proved natural gas reserves at period end	$	2.91			$	3.00			Natural gas price used to estimate proved natural gas reserves at period end	$	3.07			$	3.00

Depletion of proved oil and natural gas properties was ~~$401~~$457 million ($~~15.19~~15.47 per Boe) for the three months ended ~~September 30, 2018~~March 31, 2019, an increase of ~~$122~~$146 million ~~(44~~(47 percent) from ~~$279~~$311 million ($~~15.67~~15.13 per Boe) for ~~2017~~2018. The increase in depletion expense was primarily due to an increase in production ~~partially offset by a lower~~and the depletion rate per Boe. The ~~decrease~~increase in depletion expense per Boe was primarily due to the increase in proved reserves due to our successful exploratory drilling program, cost reductions and higher oil prices. The decrease in depletion expense per Boe was partially offset by an increase in capitalized leasehold costs from the RSP Acquisition.

General and administrative expenses. The following table provides components of our general and administrative expenses for the three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017:~~2018:


		Three Months Ended September 30,									Three Months Ended March 31,
		2018				2017					2019				2018
				Per				Per					Per				Per
(in millions, except per unit amounts)	(in millions, except per unit amounts)	Amount		Boe		Amount		Boe		(in millions, except per unit amounts)	Amount		Boe		Amount		Boe

General and administrative expenses	General and administrative expenses	$	65	$	2.46	$	51	$	2.89	General and administrative expenses	$	71	$	2.40	$	52	$	2.68
Less: Operating fee reimbursements	Less: Operating fee reimbursements		(4)		(0.19)		(4)		(0.24)	Less: Operating fee reimbursements		(4)		(0.13)		(4)		(0.21)
Non-cash stock-based compensation	Non-cash stock-based compensation		23		0.86		17		0.95	Non-cash stock-based compensation		24		0.81		17		0.84
	Total general and administrative expenses	$	84	$	3.13	$	64	$	3.60	Total general and administrative expenses	$	91	$	3.08	$	65	$	3.31

~~General~~Total general and administrative expenses were approximately ~~$84~~$91 million ($~~3.13~~3.08 per Boe) for the three months ended ~~September 30, 2018~~March 31, 2019, an increase of ~~$20~~$26 million ~~(31~~(40 percent) from ~~$64~~$65 million ($~~3.60~~3.31 per Boe) for ~~2017~~2018. The increases in cash general and administrative and non-cash stock-based compensation expenses were primarily the result of increased employee headcount. The decrease in total general and administrative expenses per Boe was primarily the result of increased production, partially offset by the increase in total general and administrative expenses noted above.

We receive fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and record such reimbursements as reductions to general and administrative expenses on the consolidated statements of operations. We earned reimbursements of approximately $4 million ~~and $4 million~~ for each of the three months ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017, respectively.~~.

4441

~~Gain (loss)~~Loss on derivatives. The following table sets forth the ~~gain (loss)~~loss on derivatives for the three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017:~~2018:


			Three Months Ended						Three Months Ended
			September 30,						March 31,
(in millions)	(in millions)			2018		2017	(in millions)			2019		2018

*Gain (loss) on derivatives:*
*Loss on derivatives:*							*Loss on derivatives:*
	Oil derivatives		$	(626)	$	(205)	Oil derivatives		$	(1,056)	$	(33)
	Natural gas derivatives			1		(1)	Natural gas derivatives			(3)		(2)
		Total	$	(625)	$	(206)		Total	$	(1,059)	$	(35)


The following table represents our net cash receipts from (payments on) derivatives for the three months ended September 30, 2018 and 2017:
The following table represents our net cash receipts from (payments on) derivatives for the three months ended March 31, 2019 and 2018:							The following table represents our net cash receipts from (payments on) derivatives for the three months ended March 31, 2019 and 2018:


			Three Months Ended						Three Months Ended
			September 30,						March 31,
(in millions)	(in millions)			2018		2017	(in millions)			2019		2018

*Net cash receipts from (payments on) derivatives:*	*Net cash receipts from (payments on) derivatives:*						*Net cash receipts from (payments on) derivatives:*
	Oil derivatives		$	(46)	$	28	Oil derivatives		$	3	$	(113)
	Natural gas derivatives			2		2	Natural gas derivatives			(3)		1
		Total	$	(44)	$	30		Total	$	-	$	(112)

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains; while to the extent the future commodity price outlook increases between measurement periods, we will have mark-to-market losses. See Note 7 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding significant judgments made in classifying financial instruments in the fair value hierarchy.

~~Interest expense.~~ ~~The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the three months ended September 30, 2018 and 2017:~~

Three Months Ended

September 30,
(in millions)

2018

2017

Interest expense, as reported

$
46

$
39
Capitalized interest

2

-

Interest expense, excluding impact of capitalized interest

$
48

$
39



Weighted average interest rate - credit facility

4.8%

4.8%
Weighted average interest rate - senior notes

4.4%

5.2%

Total weighted average interest rate


4.4%

5.2%

Weighted average credit facility balance

$
152

$
12
Weighted average senior notes balance


3,982

2,731

Total weighted average debt balance

$
4,134

$
2,743

The increase in interest expense was due to the increase in the weighted average debt balance, partially offset by the decrease in the weighted average interest rate and an increase in capitalized interest. The increase in the weighted average debt balance was due primarily to the Notes issued in connection with the RSP Acquisition.

~~Loss on extinguishment of debt.~~ We recorded a loss on extinguishment of debt of approximately $65 million for the three months ended September 30, 2017. This amount includes approximately $36 million associated with the premium paid for the cash tender offer and redemption of all of the outstanding $600 million aggregate principal amount of our 5.5% unsecured senior notes due 2022 and $1,550 million aggregate principal amount of our 5.5% unsecured senior notes due 2023 (collectively, the “5.5% Notes”), approximately $25 million associated with the make-whole premium paid for the early extinguishment of the 5.5% Notes, approximately $21 million of unamortized deferred loan costs and approximately $2 million of additional interest on the 5.5% Notes to October 13, 2017, which was paid in September 2017, reduced by approximately $19 million of unamortized premium.

~~Income tax provisions.~~ ~~For the three months ended~~ ~~September 30, 2018 and 2017, we recorded an income tax benefit of approximately $69 million and $66 million, respectively. The amount for the three months ended~~ ~~September 30, 2018~~ ~~includes discrete income tax benefits of approximately $7 million, primarily related to a change in our estimated state tax rate.~~

~~The effective income tax rates for the three months ended~~ ~~September 30, 2018 and 2017~~ ~~were 26 percent and 37 percent, respectively. The change in our effective income tax rate was primarily due to the decrease in the U.S. federal statutory rate from 35 percent to 21 percent.~~

~~Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017~~

~~Oil and natural gas revenues.~~ ~~Revenue from oil and natural gas operations was$3,084 million for the nine months ended~~ ~~September 30, 2018, an increase of$1,278 million (71~~ ~~percent) from $1,806 million for~~ ~~2017~~. This increase was primarily due to the increase in oil and natural gas production as well as the increase in realized oil and natural gas prices (excluding the effects of derivative activities). Additionally, on January 1, 2018, we adopted ASC 606, which requires certain costs related to gathering, processing and transportation to be separately presented on the consolidated statements of operations. Prior to the adoption of ASC 606, these costs were generally accounted for as a deduction to revenue and included within total operating revenues on the consolidated statements of operations. We elected to use the modified retrospective approach for adopting ASC 606, and as such prior period amounts have not been restated. See Note 2 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding the adoption of ASC 606. Specific factors affecting oil and natural gas revenues include the following:

·~~total oil production was 42,947 MBbl for the nine months ended September 30, 2018, an increase of 11,420 MBbl (36 percent) from 31,527 MBbl for 2017;~~

·~~average realized oil price (excluding the effects of derivative activities) was~~ ~~$59.25~~ ~~per Bbl during the nine months ended~~ ~~September 30, 2018, an increase of 28~~ ~~percent~~ ~~from~~ ~~$46.34~~ ~~per Bbl during~~ ~~2017~~. For the nine months ended September 30, 2018, our crude oil price differential relative to NYMEX was $(7.58) per Bbl, or a realization of approximately 89 percent, as compared to a crude oil price differential relative to NYMEX of $(3.11) per Bbl, or a realization of approximately 94 percent, for 2017. The basis differential (referred to as the “Mid-Cush differential”) between the location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil directly impacts our realized oil price. For the nine months ended September 30, 2018 and 2017, the average market Mid-Cush differentials were price reductions of $(5.81) per Bbl and $(0.31) per Bbl, respectively. Our crude oil price differential relative to NYMEX excluding the Mid-Cush differential was $(1.77) per Bbl for the nine months ended September 30, 2018, as compared to $~~(2.80)~~ ~~per Bbl for the nine months ended September 30, 2017.~~ ~~This difference was due to the fluctuation between the price we receive, which is based on a calendar month average, as compared to NYMEX;~~

·~~total natural gas production was 148,633 MMcf for the nine months ended September 30, 2018, an increase of 32,392 MMcf (28 percent) from 116,241 MMcf for 2017; and~~

·~~average realized natural gas price (excluding the effects of derivative activities) was~~ ~~$3.63~~ ~~per Mcf during the nine months ended~~ ~~September 30, 2018, an increase of 23~~ ~~percent~~ ~~from~~ ~~$2.96~~ ~~per Mcf during~~ ~~2017. For the nine months ended~~ ~~September 30, 2018 and 2017, we realized approximately 127 percent and 97 percent, respectively, of the average NYMEX natural gas prices for the respective periods.~~ ~~Historically, and during the~~ ~~nine~~ months ended September 30, 2018, we derived a significant portion of our total natural gas revenues from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues, our realized natural gas price (excluding the effects of derivatives) reflected a price greater than the related NYMEX natural gas price for the ~~nine months ended~~ ~~September 30, 2018. The increase in our realized natural gas price (excluding the effects of derivatives) as a percentage of NYMEX during the~~ ~~nine~~ ~~months ended September 30, 2018 as compared to 2017 was primarily due to an increase in the average Mont Belvieu price for a blended barrel of natural gas liquids, which was~~ ~~$30.73~~ ~~per Bbl and~~ ~~$23.74~~ per Bbl during the nine months ended September 30, 2018 and 2017, respectively. The increase in our realized natural gas price was also due to the adoption of ASC 606, as our natural gas realized price was $0.14 per Mcf higher than what it would have been under the previous revenue standard.

~~Oil and natural gas production expenses.~~ ~~The following table provides the components of our oil and natural gas production expenses for the nine months ended September 30, 2018 and 2017:~~

Nine Months Ended September 30,

2018

2017

Per

Per
(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

Lease operating expenses

$
388

$
5.73

$
278

$
5.47
Workover costs


28

0.42

15

0.29

Total oil and natural gas production expenses

$
416

$
6.15

$
293

$
5.76

~~Lease operating expenses were $388 million ($5.73 per Boe) for the nine months ended~~ ~~September 30, 2018, which was an increase of $110 million from $278 million ($5.47 per Boe) during~~ ~~2017. The increase in lease operating expenses during the nine months ended~~ ~~September 30, 2018~~ as compared to 2017 was primarily due to (i) increased production and activities associated with the additional wells successfully drilled and completed and the RSP Acquisition, (ii) our acquisitions and nonmonetary transactions during the fourth quarter of 2017 and first nine months of 2018, particularly our July 2017 Midland Basin acquisition and our February 2018 acquisition and divestiture, whose associated properties incur higher lease operating expense per Boe than our legacy assets and (iii) increased cost of services. The increase in lease operating expenses per Boe was primarily due to the increase in lease operating expenses noted above, partially offset by an increase in production.

~~Workover costs were $28 million ($0.42 per Boe) for the nine months ended~~ ~~September 30, 2018, which was an increase of $13 million from $15 million ($0.29 per Boe) during~~ ~~2017. The increase in workover costs during the nine months ended~~ ~~September 30,~~ 2018 as compared to 2017 was primarily due to increased workover activity and cost of services. The increase in workover costs per Boe was primarily due to the increase in workover costs noted above, partially offset by an increase in production.

~~Production and ad valorem taxes.~~ ~~The following table provides the components of our production and ad valorem tax expenses for the nine months ended~~ ~~September 30, 2018~~ ~~and 2017:~~

Nine Months Ended September 30,

2018

2017

Per

Per
(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

Production taxes

$
207

$
3.05

$
128

$
2.52
Ad valorem taxes


22

0.33

12

0.23

Total production and ad valorem taxes

$
229

$
3.38

$
140

$
2.75

~~Production taxes per unit of production were $3.05 per Boe during the nine months ended~~ ~~September 30, 2018, an increase of 21 percent from $2.52 per Boe during~~ ~~2017~~. Over the same period, our revenue per Boe (excluding the effects of derivatives) increased 28 percent. The increase in production taxes per unit of production was directly related to the increase in oil and natural gas sales, partially offset by a higher percentage of our total production originating in Texas, which has a lower tax rate than New Mexico. Production taxes fluctuate with the market value of our production sold, while ad valorem taxes are generally based on the valuation of our oil and natural gas properties at the beginning of the year, which vary across the different areas in which we operate.

~~Gathering, processing and transportation costs.~~ ~~The following table shows the gathering, processing and transportation costs for the nine months ended~~ ~~September 30, 2018~~:

Nine Months Ended

September 30, 2018

Per
(in millions, except per unit amounts)

Amount

Boe

Gathering, processing and transportation costs

$
36

$
0.53

~~Gathering, processing and transportation costs were $36 million ($0.53 per Boe) for the nine months ended~~ ~~September 30, 2018~~. On January 1, 2018, we adopted ASC 606, which requires certain amounts related to gathering, processing and transportation costs to be separately presented on the consolidated statements of operations. Prior to the adoption of ASC 606, the majority of these costs were accounted for as a deduction to revenue and included within total operating revenues on the consolidated statements of operations. We have elected to use the modified retrospective approach for adopting ASC 606, and as such, prior period amounts have not been restated.

~~Exploration and abandonments expense.~~ ~~The following table provides the components of our exploration and abandonments expense for the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2018~~ ~~and 2017:~~

Nine Months Ended

September 30,
(in millions)

2018

2017

Geological and geophysical

$
9

$
9
Leasehold abandonments

20

24
Other


7

9

Total exploration and abandonments

$
36

$
42

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

~~For the~~ ~~nine~~ ~~months ended September 30, 2018 and 2017, we recorded approximately $20 million and $24 million, respectively, of leasehold abandonments. For the~~ ~~nine~~ months ended September 30, 2018, our abandonments were primarily related to (i) expiring acreage in the Southern Delaware Basin and (ii) acreage in the Southern Delaware Basin, Northern Delaware Basin and New Mexico Shelf where we had no future plans to drill. For the ~~nine~~ months ended September 30, 2017, our abandonments were primarily related to (i) non-contiguous acreage expiring in the Southern Delaware Basin and (ii) acreage in the Northern Delaware Basin and New Mexico Shelf in locations where we have no future plans to drill.

~~Our other expense for the periods presented above primarily consists of surface and title costs on locations we no longer intend to drill, certain plugging costs and delay rentals.~~

~~Depreciation, depletion and amortization expense.~~ ~~The following table provides components of our depreciation, depletion and amortization expense for the nine months ended~~ ~~September 30, 2018~~ ~~and 2017:~~

Nine Months Ended September 30,

2018

2017

Per

Per
(in millions, except per unit amounts)


Amount

Boe

Amount

Boe

Depletion of proved oil and natural gas properties

$
1,015

$
14.99

$
830

$
16.31
Depreciation of other property and equipment


16

0.24

17

0.33
Amortization of intangible assets - operating rights


2

0.04

1

0.02

Total depletion, depreciation and amortization

$
1,033

$
15.27

$
848

$
16.66

~~Depletion of proved oil and natural gas properties was $1,015 million ($14.99 per Boe) for the nine months ended~~ ~~September 30, 2018, an increase of $185 million (22 percent) from $830 million ($16.31 per Boe) for~~ ~~2017~~. The increase in depletion expense was primarily due to an increase in production, partially offset by a lower depletion rate per Boe. The decrease in depletion expense per Boe was primarily due to the increase in proved reserves due to our successful exploratory drilling program, cost reductions and higher oil prices. The decrease in depletion expense per Boe was partially offset by an increase in capitalized leasehold costs from the RSP Acquisition.

~~General and administrative expenses.~~~~The following table provides components of our general and administrative expenses for the nine months ended~~ ~~September 30, 2018~~ ~~and 2017:~~

Nine Months Ended September 30,

2018

2017

Per

Per
(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

General and administrative expenses

$
176

$
2.60

$
149

$
2.95
Less: Operating fee reimbursements


(13)

(0.20)

(12)

(0.24)
Non-cash stock-based compensation


58

0.86

43

0.85

Total general and administrative expenses

$
221

$
3.26

$
180

$
3.56

~~General and administrative expenses were approximately $221 million ($3.26 per Boe) for the nine months ended~~ ~~September 30, 2018, an increase of $41 million (23 percent) from $180 million ($3.56 per Boe) for~~ ~~2017~~. The increase in cash general and administrative expenses was primarily driven by increased compensation expense as a result of increased employee headcount. The increase in non-cash stock-based compensation was primarily due to lower forfeitures in 2018 coupled with the increase in employee headcount. The decrease in total general and administrative expenses per Boe was primarily the result of increased production, partially offset by the increase in total general and administrative expenses noted above.

We receive fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and record such reimbursements as reductions to general and administrative expenses on the consolidated statements of operations. We earned reimbursements of approximately $13 million and $12 million for the nine months ended September 30, 2018 and 2017, respectively.

~~Gain (loss) on derivatives.~~~~The following table sets forth the gain (loss) on derivatives for the nine months ended~~ ~~September 30, 2018~~ ~~and 2017:~~

Nine Months Ended

September 30,
(in millions)

2018

2017

Gain (loss) on derivatives:

Oil derivatives

$
(787)

$
260

Natural gas derivatives

(6)

29

Total

$
(793)

$
289

     The following table represents our net cash receipts from (payments on) derivatives for the nine months ended September 30, 2018 and 2017:

Nine Months Ended

September 30,
(in millions)

2018

2017

Net cash receipts from (payments on) derivatives:

Oil derivatives

$
(245)

$
129

Natural gas derivatives


7


(3)

Total

$
(238)

$
126

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent the future commodity price outlook increases between measurement periods, we will have mark-to-market losses. See Note 76 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding significant judgments made in classifying financial instruments in the fair value hierarchy.

Gain on disposition of assets, net. During the ~~nine~~three months ended ~~September 30,~~March 31, 2018, we ~~recognized~~recorded a net gain on disposition of assets of approximately $723 million due to (i) a non-cash gain of approximately $575 million related to our February 2018 acquisition and ~~divestiture.~~

Indivestiture, (ii) a gain of approximately $134 million related to our January 2018 ~~we closed on our Southern~~ Delaware Basin divestitures ~~with combined proceeds~~and (iii) a gain of approximately ~~$280 million. After direct transaction costs, we recorded a pre-tax gain on disposition of assets of approximately $134 million.~~

~~During the nine months ended September 30, 2018, we completed multiple~~$14 million related to certain nonmonetary transactions. ~~These transactions~~See Note 4 of the Condensed Notes to Consolidated Financial Statements included ~~the exchange of both proved and unproved oil and natural gas properties. Certain of these transactions were accounted~~in “Item 1. Consolidated Financial Statements (Unaudited)” for ~~at fair value and, as a result, we recorded pre-tax gains of approximately $15 million.~~

In February 2017, we closed on the divestiture of our ownership interest in ACC. After adjustments for debt and working capital, we received cash proceeds from the sale of approximately $801 million. After direct transaction costs, we recorded a pre-tax gain on disposition of assets of approximately $655 million. Our net investment in ACC at the time of closing was approximately $129 million.additional information.

5142

Interest expense.The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017:~~2018:


		Nine Months Ended					Three Months Ended
		September 30,					March 31,
(in millions)	(in millions)	2018		2017		(in millions)	2019		2018

Interest expense, as reported	Interest expense, as reported	$	103	$	118	Interest expense, as reported	$	47	$	30
Capitalized interest	Capitalized interest		5		-	Capitalized interest		4		1
	Interest expense, excluding impact of capitalized interest	$	108	$	118	Interest expense, excluding impact of capitalized interest	$	51	$	31

Weighted average interest rate - credit facility	Weighted average interest rate - credit facility		4.6%		4.5%	Weighted average interest rate - credit facility		4.4%		4.3%
Weighted average interest rate - senior notes	Weighted average interest rate - senior notes		4.3%		5.2%	Weighted average interest rate - senior notes		4.4%		4.3%
	Total weighted average interest rate		4.3%		5.2%	Total weighted average interest rate		4.4%		4.3%

Weighted average credit facility balance	Weighted average credit facility balance	$	138	$	6	Weighted average credit facility balance	$	503	$	211
Weighted average senior notes balance	Weighted average senior notes balance		2,927		2,744	Weighted average senior notes balance		4,000		2,400
	Total weighted average debt balance	$	3,065	$	2,750	Total weighted average debt balance	$	4,503	$	2,611

The ~~decrease~~increase in interest expense was primarily due to ~~the decrease in the weighted average interest rate and an increase in capitalized interest, partially offset by~~ the increase in the weighted average debt ~~balance.~~

balance, partially offset by the increase in capitalized interest. The increase in the weighted average debt balance was primarily due ~~primarily~~ to the ~~Notes~~senior notes issued in connection with the RSP ~~Acquisition.~~

~~Loss on extinguishment of debt.~~ ~~We recorded~~Acquisition and a ~~loss on extinguishment of debt of approximately $66 million for~~higher average outstanding balance under the nine months ended September 30, 2017. This amount includes: (i) approximately $36 million associated with the premium paid for the cash tender offer and redemption of the 5.5% Notes, approximately $25 million associated with the make-whole premium paid for the early extinguishment of the 5.5% Notes, approximately $21 million of unamortized deferred loan costs and approximately $2 million of additional interest on the 5.5% Notes to October 13, 2017, which was paid in September 2017, reduced by approximately $19 million of unamortized premium; and (ii) approximately $1 million representing 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 credit facility amendment.Credit Facility.

Other income, net. During the ~~nine~~three months ended ~~September 30,~~March 31, 2018, we recorded other income of approximately ~~$108~~$104 million, primarily related to a cash distribution received from Oryx. See Note 2 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding this distribution.

Income tax provisions. For the ~~nine~~three months ended ~~September 30, 2018 and 2017, we~~March 31, 2019, we recorded an income tax benefit of approximately $194 million compared to an income tax expense of approximately ~~$225~~$254 million ~~and $398 million, respectively. The amount~~ for the ~~nine~~three months ended ~~September 30, 2018 includes discrete income tax benefits of approximately $7 million,~~March 31, 2018. The change is primarily ~~related~~due to ~~a change in our estimated state tax rate. The amounts~~the pre-tax loss for the ~~nine~~three months ended ~~September 30, 2018 and 2017 include discrete~~March 31, 2019 as compared to the pre-tax income ~~tax benefits of approximately $3 million and $6 million, respectively, related to excess tax benefits on stock-based awards.~~for the three months ended March 31, 2018.

The effective income tax rates for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ were 2322 percent and 3723 percent, respectively. The change in our effective income tax rate was primarily due to the ~~decrease in~~research and development credit, net of unrecognized tax benefits, partially offset by the ~~U.S. federal statutory rate from 35 percent~~impact of other items. We recorded a discrete income tax benefit related to ~~21 percent.~~stock-based awards of approximately $2 million for each of the three months ended March 31, 2019 and 2018.

5243

Capital Commitments, Capital Resources and Liquidity

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

~~Oil~~2019 capital budget and ~~natural gas properties.~~costs incurred. We expect our 2019 capital spending on drilling and completion activity to range between $2.8 billion and $3.0 billion. Our costs incurred on oil and natural gas properties, excluding acquisitions, during the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017~~2018 totaled ~~$1.7 billion~~$926 million and ~~$1.2 billion,~~$450 million, respectively. ~~The increase was primarily due to our increased drilling and completion activity level during the first~~ ~~nine~~ ~~months of 2018 as compared to 2017.~~ Our intent is to manage our capital spending to be within our operating cash flow, excluding unbudgeted acquisitions. The primary reason for the differences in costs incurred and cash flow expenditures was the timing of payments. ~~Total 2018~~Our capital expenditures for the three months ended March 31, 2019 were primarily funded ~~in part~~ from cash flows from operations and ~~proceeds from~~borrowings under our ~~January 2018 Southern Delaware Basin divestitures.~~Credit Facility.

~~2018 capital budget.~~ In July 2018, our board approved a revised 2018 capital budget of up to $2.7 billion. The revised budget includes capital we plan to invest during the second half of the year on the acquired RSP assets. We expect our 2018 capital spending on drilling and completion activity to range between $2.5 billion and $2.6 billion. Our 2018 capital budget, excluding acquisitions and based on our current expectations of commodity prices and costs, is expected to be within our operating cash flows.

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

2019 dividends. On February 19, 2019, our board of directors declared a cash dividend of $0.125 per share. The total cash dividend, including the cash dividend paid on unvested restricted stock awards, of $25 million was paid on March 29, 2019 to stockholders as of March 1, 2019. On April 30, 2019, our board of directors approved a cash dividend of $0.125 per share for the ~~RSP Acquisition.~~second quarter of 2019 that is expected to be paid on June 28, 2019 to stockholders of record as of May 10, 2019. We intend to continue to pay a quarterly dividend of $0.125 in the near future; however, any payment of future dividends will be at the discretion of our board of directors.

Acquisitions. The following table reflects our expenditures for acquisitions of proved and unproved properties for the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017:~~2018:


			Nine Months Ended						Three Months Ended
			September 30,						March 31,
(in millions)	(in millions)		2018		2017		(in millions)		2019		2018

Property acquisition costs:	Property acquisition costs:						*Property acquisition costs:*
	Proved		$	4,126	$	301	Proved		$	-	$	-
	Unproved			3,596		865	Unproved			4		13
		Total property acquisition costs (a)	$	7,722	$	1,166		Total property acquisition costs (a)	$	4	$	13


(a)	Included in the property acquisition costs above are budgeted unproved leasehold acreage acquisitions of approximately $31 million and td6 million for the nine months ended September 30, 2018 and 2017, respectively. For the nine months ended September 30, 2018, our unbudgeted acquisitions are primarily comprised of approximately $7.6 billion of property acquisition costs related to the RSP Acquisition. For the nine months ended September 30, 2017, our unbudgeted acquisitions are primarily comprised of approximately $603 million and $452 million of property acquisition costs related to our Midland Basin and Northern Delaware Basin acquisitions, respectively.						Included in the property acquisition costs above are budgeted unproved leasehold acreage acquisitions of approximately $4 million and td3 million for the three months ended March 31, 2019 and 2018, respectively.

5344

Contractual obligations. Our contractual obligations include long-term debt, cash interest expense on debt, derivative liabilities, asset retirement obligations, employment agreements with officers, purchase obligations, operating and finance lease obligations and other obligations. Since December 31, ~~2017,~~2018, there have been the following material changes in our contractual obligations:

· $~~1,471~~373 million increase in long-term debt due to ~~the issuance of the 4.3% Notes and 4.85% Notes, partially offset by a decrease in~~additional borrowings under our Credit ~~Facility balance;~~Facility;

· $~~1,227 million increase in cash interest expense on debt due to the issuance of the 4.3% Notes and 4.85% Notes;~~

·~~$531~~367 million increase in our derivative liability position;

·$243 million increase in purchase obligations mainly due to contracts assumed in the RSP Acquisition, including additional throughput volume delivery commitments, power commitments, daywork drilling contracts and sand commitment agreements; and

· a ~~throughput sales commitment~~marketing contract as described below.

~~Throughput sales commitment.~~Marketing contract. ~~In May 2018,~~Consistent with our strategy of diversifying our oil pricing, in January 2019, we entered into a ~~one-year term oil marketing contract~~firm sales agreement with a third-party purchaser. The ~~contract~~purchaser provides integrated transportation and marketing optionality, including dock capacity in Corpus Christi, Texas. The agreement has a term that ends five years after the startup of Cactus II Pipeline system and requires us to deliver ~~not less than seven thousand~~50,000 barrels of oil per day. Should there be a delivery shortfall in any given month, we retain 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 thenday that will receive waterborne market ~~price for oil. If production is not sufficient to meet the sales commitment, we may purchase commodities in the market to satisfy our commitment.~~pricing.

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

Capital resources. Our primary sources of liquidity have been cash flows generated from (i) operating activities, (ii) borrowings under our Credit Facility, (iii) asset dispositions and (iv) proceeds from bond and equity ~~offerings and (iv) asset dispositions.~~offerings. In ~~July~~October 2018, our board of directors approved ~~a revised 2018~~our 2019 capital budget of up to ~~$2.7~~$3.8 billion. ~~The revised budget includes capital~~With current commodity prices, we ~~plan~~expect to ~~invest during the second half of the year on the acquired RSP assets. We expect our 2018 capital spending~~spend between $2.8 billion and $3.0 billion on drilling and completion ~~activity~~activity. We expect to ~~range between $2.5 billion and $2.6 billion. Our 2018~~ fund our 2019 capital budget ~~excluding acquisitions and based on our current expectations of commodity prices and costs, is expected to be within our~~with operating cash ~~flows.~~flows and borrowings under our Credit Facility.

The following table summarizes our changes in cash and cash equivalents for the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017:~~2018:


		Nine Months Ended					Three Months Ended
		September 30,					March 31,
(in millions)	(in millions)	2018		2017		(in millions)	2019		2018

Net cash provided by operating activities	Net cash provided by operating activities	$	1,861	$	1,185	Net cash provided by operating activities	$	623	$	488
Net cash used in investing activities	Net cash used in investing activities		(1,422)		(1,207)	Net cash used in investing activities		(902)		(93)
Net cash used in financing activities			(415)		(31)
Net cash provided by (used in) financing activities						Net cash provided by (used in) financing activities		279		(395)
	Net increase (decrease) in cash and cash equivalents	$	24	$	(53)	Net increase in cash and cash equivalents	$	-	$	-

Cash flow from operating activities. The increase in operating cash flows during the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2019 as compared to the same period in ~~2017~~2018 was primarily due to an increase in oil and natural gas revenues of ~~approximately $1,278~~$157 million ~~partially offset by (i) a decrease in operating cash flow~~and an increase of ~~approximately $364~~$112 million due to approximately zero net cash settlements on derivatives during the three months ended March 31, 2019, as compared to $~~238~~112 million ~~for~~in settlements paid on derivatives during the ~~nine months ended September 30, 2018, as compared to approximately $126~~ ~~million in settlements received from derivatives during the~~ comparable period in ~~2017,~~2018. The increase was partially offset by a ~~(ii) approximately $123~~$44 million increase in production expense, a $19 million increase in cash general and ~~(iii) approximately $89~~administrative expense and a $16 million increase in production tax expense.

Our net cash provided by operating activities included a ~~benefit~~reduction of ~~approximately $3~~$78 million and ~~a reduction of approximately $59~~$51 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

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

For the three months ended ~~September 30, 2018~~March 31, 2019 ~~and 2017, we invested approximately $1,669~~, our net cash used in investing activities was $902 million, ~~and $1,092~~which consisted primarily of our investment of $885 million ~~respectively,~~ for additions to oil and natural gas properties. ~~Additionally, we~~Our capital expenditures for the three months ended March 31, 2019 were funded with cash flows from operations and borrowings under our Credit Facility.

During the three months ended March 31, 2018, our net cash used ~~approximately $105~~in investing activities was $93 million, ~~and $866~~which consisted primarily of our investment of $474 million ~~of cash~~for additions to ~~fund certain acquisitions of~~ oil and natural gas properties, ~~during the nine months ended~~ ~~September 30, 2018~~partially offset by $255 million of proceeds received from asset dispositions and ~~2017, respectively~~.a distribution received from our equity method investment. We received ~~approximately $~~a

~~260~~ 45~~million related to proceeds from the disposition of assets during the nine months ended~~ ~~September 30, 2018,~~

~~as compared to $~~

~~803~~ ~~million during the comparable period of 2017. Finally, we received an equity method investment~~ distribution from Oryx of ~~approximately~~ $157 million during the ~~nine~~three months ended ~~September 30,~~March 31, 2018. Of this amount, ~~approximately~~ $9 million represented cumulative Oryx earnings and was classified as cash flow from operating activities, while the remaining amount of ~~approximately~~ $148 million was classified as cash flow from investing activities.

Cash flow from financing activities. ~~Net~~For the three months ended March 31, 2019, our net cash provided by financing activities was $279 million primarily due to $373 million of net borrowings under our Credit Facility partially offset by $25 million of dividends paid on our common stock. During the three months ended March 31, 2019, we decreased our bank overdraft by $54 million. For the three months ended March 31, 2018, our net cash used in financing activities was ~~approximately $415~~$395 million, ~~and $31 million for the~~ ~~nine~~ ~~months ended September 30, 2018 and 2017, respectively. Below is a description of our significant financing activities:~~

·~~In July 2018, we issued $1,600 million in aggregate principal amount of the Notes, for which we received net proceeds of approximately $1,579 million. We used the net proceeds~~primarily due to redeem and cancel the RSP Notes. We 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. We also paid accrued interest of approximately $14 million on the RSP Notes. The remaining proceeds, along with borrowings under our Credit Facility, were used to repay the $540$322 million of ~~outstanding principal under RSP’s revolving credit facility, including $1 million in accrued interest.~~

·In September 2017, we issued $1,800 million in aggregate principal amount of the 3.75% unsecured senior notes due 2027 and 4.875% unsecured senior notes due 2047, for which we received net proceeds of approximately $1,777 million. We used the net proceeds from the offering, together with cash on hand and borrowings under our Credit Facility, to fund the (i) cash tender offer of $1,232 million principal amount of our 5.5% Notes at a price equal to 102.934 percent of par and (ii) satisfaction and discharge of our remaining obligations of $918 million principal amount under the indentures of the 5.5% Notes at a price equal to 102.75 percent of par. The early extinguishment price included approximately $36 million associated with the premium paid for the tender offer, approximately $25 million for the make-whole premium paid for the early extinguishment of the 5.5% Notes and approximately $2 million for prepaid interest as part of the satisfaction and discharge.

·~~During the first nine months of~~ ~~2018, we had~~ net payments ~~on our Credit Facility of $129~~ ~~million.~~

·~~During the first nine months of~~ ~~2017, we borrowed $368 million~~ on our Credit Facility.

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

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

(a) the prime rate of JPMorgan Chase Bank ~~(5.25~~(5.5 percent at ~~September 30, 2018)~~March 31, 2019),

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

(ii) ~~LIBOR.~~LIBOR plus 1.5 percent.

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

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

Liquidity. Our principal ~~sources~~source of liquidity ~~are cash on hand and~~is the available borrowing capacity under our Credit Facility. At ~~September 30, 2018, we had approximately~~ ~~$24~~ ~~million of cash on hand.~~ At ~~September 30, 2018,~~March 31, 2019, our commitments from our bank group were $2.0 billion, of which ~~$1.8~~$1.4 billion was unused commitments.

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

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

As of the filing of this Quarterly Report on Form 10-Q, no changes in our credit ratings have ~~occurred since~~ ~~September 30, 2018~~;occurred; however, we cannot be ~~assured~~certain that our credit ratings will not be downgraded in the future.

Book capitalization and current ratio. Our net book capitalization at ~~September 30, 2018~~March 31, 2019 was ~~$21.3~~$22.7 billion, consisting of debt of $~~4.1~~4.6 billion and stockholders’ equity of $~~17.2~~18.1 billion. Our net book capitalization at December 31, ~~2017~~2018 was ~~$11.6~~$23.0 billion, consisting of debt of ~~$2.7~~$4.2 billion and stockholders’ equity of ~~$8.9~~$18.8 billion. Our ratio of net debt to net book capitalization was 1920 percent and 2318 percent at ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, respectively. Our ratio of current assets to current liabilities was ~~0.55~~0.62 to 1.0 at ~~September 30, 2018~~March 31, 2019 as compared to ~~0.51~~1.04 to 1.0 at December 31, ~~2017.~~2018.

5646

Critical Accounting Policies, Practices and Estimates

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

In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets, valuation of stock-based compensation, valuation of business combinations, accounting and valuation of nonmonetary transactions, goodwill impairment, litigation and environmental contingencies, valuation of financial derivative instruments, ~~and income taxes. In addition to these areas, goodwill impairment,~~ uncertain tax positions and ~~litigation and environmental contingencies are also considered critical estimates and are discussed below.~~income taxes.

~~Goodwill impairment.~~Impairment of Long-Lived Assets

~~Goodwill is not amortized but assessed~~All of our long-lived assets are monitored for potential impairment onwhen circumstances indicate that the carrying value of an ~~annual basis, or more frequently if indicators~~asset may be greater than management’s estimates of ~~impairment exist. Impairment tests, which involve~~its future net cash flows, including cash flows from proved reserves, risk-adjusted probable and possible reserves, and integrated assets. If the ~~use of estimates related to the fair market~~carrying value of the ~~business operations with which goodwill~~long-lived assets exceeds the sum of estimated undiscounted future net cash flows, an impairment loss is ~~associated, will be performed as of July 1 of each year. As we operate as a single operating segment~~recognized for the difference between the estimated fair value and ~~a single reporting unit, we evaluate goodwill for impairment based on an evaluation of~~ the ~~fair~~carrying value of the ~~company~~assets. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as ~~a whole. The fair value~~future sales prices for oil and natural gas, future costs to produce these products, estimates of ~~the reporting unit is our enterprise value (combined market capitalization of our equity plus a control premium~~future oil and natural gas reserves to be recovered and the ~~fair value~~timing thereof, the economic and regulatory climates, cash flows from integrated assets and other factors. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimated quantities of oil and natural gas reserves. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. At March 31, 2019, our ~~long-term debt). There is considerable judgment involved in estimating fair values, particularly in~~estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the ~~control premium. To establish~~NYMEX strip, ranged from a ~~reasonable control premium, we will consider~~2019 price of $60.36 per barrel of oil decreasing to a 2026 price of $53.52 per barrel of oil. Natural gas prices ranged from a 2019 price of $2.80 per Mcf of natural gas decreasing to a 2021 price of $2.65 per Mcf then rising to a 2026 price of $3.01 per Mcf of natural gas. Both oil and natural gas commodity prices for this purpose were held flat after 2026. We did not recognize an impairment charge during the premiums paid in recent market acquisitions and will analyze current industry, market and economic conditions along with other factors or available information specific to our business. See Note 2 and 4 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding goodwill.

~~Uncertain tax positions.~~ We recognize 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 September 30, 2018, we had unrecognized tax benefits of approximately $20 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 our deferred tax liability and will affect our effective tax rate in the period it is recognized. See Note 11 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding uncertain tax positions.three months ended March 31, 2019.

~~Litigation~~It is reasonably possible that the estimates of undiscounted future net cash flows of our long-lived assets may change in the future resulting in the need to impair carrying values. We estimate that if the future oil and ~~environmental contingencies.~~natural gas prices used in this analysis, and noted above, would have been approximately 10 percent lower at March 31, 2019, with no other changes in capital costs, operating costs, price differentials or reserve performance curves, the carrying amount of our Yeso field would have exceeded the expected undiscounted future net cash flow, and an impairment of approximately $800 million would have been recorded. Other assumptions such as operating costs, well and reservoir performance, severance and ad valorem taxes and operating and development plans would likely change given a change in oil and natural gas prices. However, we did not estimate the correlation between these assumptions and any estimated commodity price change, and these and other assumptions may worsen or partially mitigate some of the effects of a reduction in commodity prices, including the ultimate impact and amount of any potential impairment charge. As a result, we are unable to predict with certainty whether or not a decline in commodity prices alone will or will not cause us to recognize an impairment charge in a particular field or the magnitude of any such impairment charge. We ~~make judgments~~additionally note that there may be changes to both drilling and completion designs that affect the volume curves, capital costs estimates ~~in recording liabilities for ongoing litigation~~ and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the amount of ~~damages. Similarly, environmental remediation liabilities are subject to change because~~proved undeveloped locations that can be recorded, each of ~~changes in laws and regulations, developing information relating to the extent and nature~~which will affect management’s estimates of site contamination and improvements in technology. A liability is recorded for these types of contingencies if we determine the loss to be both probable and reasonably estimable. See Note 10 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commitments and contingencies.future cash flows.

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

There have been no material changes ~~except those discussed above,~~ in our critical accounting policies and procedures during the ~~nine~~three months ended ~~September 30, 2018.~~March 31, 2019. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, ~~2017,~~2018, filed with the~~U.S.~~ Securities and Exchange Commission ~~(the “SEC”~~(“SEC”) on February ~~21, 2018.~~20, 2019.

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

5748

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

We are exposed to a variety of market risks, including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we are a party at ~~September 30, 2018~~March 31, 2019, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit. We do not enter into derivative or other financial instruments for speculative or trading purposes.

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

Credit risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our oil and natural gas production, which we market to energy marketing companies and refineries, and to a lesser extent, our derivative counterparties. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness.

We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set-off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 87 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative activities.

Commodity price risk. We are exposed to market risk as the prices of our commodities are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of our commodities, we have entered into, and may in the future enter into, additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Our commodity price risk management arrangements are recorded at fair value and thus changes to the future commodity prices will have an impact on net income. The following table sets forth the hypothetical impact on the fair value of the commodity price risk management arrangements from an average increase and decrease in the commodity price of $5.00 per Bbl of oil and $0.50 per MMBtu of natural gas from the commodity prices at ~~September 30, 2018:~~March 31, 2019:


				Increase of		Decrease of				Increase of		Decrease of
				$5.00 per Bbl and		$5.00 per Bbl and				$5.00 per Bbl and		$5.00 per Bbl and
(in millions)	(in millions)			$0.50 per MMBtu		$0.50 per MMBtu	(in millions)			$0.50 per MMBtu		$0.50 per MMBtu

Gain (loss):	Gain (loss):						Gain (loss):
	Oil derivatives		$	(405)	$	403	Oil derivatives		$	(439)	$	439
	Natural gas derivatives			(26)		26	Natural gas derivatives			(35)		35
		Total	$	(431)	$	429		Total	$	(474)	$	474

5849

At ~~September 30, 2018~~March 31, 2019, we had (i) oil price swaps ~~oil three-way collars~~ and oil costless collars covering future oil production ~~to effectively provide NYMEX price hedges~~ from ~~October~~April 1, ~~2018~~2019 through December 31, ~~2020~~2021 and (ii) oil basis swaps ~~to effectively provide price hedges for~~covering our Midland to Cushing basis differential from ~~October~~April 1, ~~2018~~2019 to December 31, ~~2020.~~2021. The ~~average~~ NYMEX oil price ~~for the~~at ~~nine~~ ~~months ended~~ ~~September 30, 2018~~March 31, 2019 was ~~$66.83~~$60.14 per Bbl. At ~~October~~April 29, ~~2018~~2019, the NYMEX oil price was ~~$67.04~~$63.50 per Bbl.

At ~~September 30, 2018~~March 31, 2019, we had natural gas price swaps that settle on a monthly basis covering future natural gas production from ~~October~~April 1, ~~2018~~2019 to December 31, 2020. The ~~average~~ NYMEX natural gas price ~~for the nine~~ ~~months ended~~at ~~September 30, 2018~~March 31, 2019 was $~~2.85~~2.66 per MMBtu. At ~~October~~April 29, ~~2018,~~2019, the NYMEX natural gas price was $~~3.19~~2.59 per MMBtu.

A decrease in the average forward NYMEX oil and natural gas prices below those at ~~September 30, 2018~~March 31, 2019 would decrease the fair value liability of our commodity derivative contracts from their recorded balance at ~~September 30, 2018~~March 31, 2019. Changes in the recorded fair value of our commodity derivative contracts are marked to market through earnings as gains or losses. The potential decrease in our fair value liability would be recorded in earnings as a gain. However, an increase in the average forward NYMEX oil and natural gas prices above those at ~~September 30, 2018~~March 31, 2019 would increase the fair value liability of our commodity derivative contracts from their recorded balance at ~~September 30, 2018~~March 31, 2019. The potential increase in our fair value liability would be recorded in earnings as a loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.

We recorded a loss on derivatives of ~~$793~~$1,059 million and $35 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018, ~~compared to a gain of $289 million for the~~ ~~nine~~ ~~months ended September 30, 2017.~~respectively. The ~~decrease~~increase in loss on derivatives was primarily due to the change in commodity future price curves at the respective measurement and settlement periods.

The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method for our derivative instruments during the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2019. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2019:

Commodity Derivative

Instruments

(in millions)

Net Assets (Liabilities) ~~(a)~~

Fair value of contracts outstanding at December 31, ~~2017~~2018

~~(379)~~695

Changes in fair values ~~(b)~~(a)

~~(793)~~(1,059)

Contract maturities

~~238~~-

~~Fair value of RSP contracts acquired~~

Fair value of contracts outstanding at ~~September 30, 2018~~March 31, 2019 (b)

~~(910)~~(364)

(a)

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

(b)

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

See Note 87 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments.

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

We had total indebtedness of ~~$193~~$615 million outstanding under our Credit Facility at ~~September 30, 2018~~March 31, 2019. The impact of a one percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $2$6 million.

5950

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at ~~September 30, 2018~~March 31, 2019 at the reasonable assurance level.

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

6051

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

On July 30, 2018, the owners of certain mineral and surface interests on the Mabee Ranch in Martin and Andrews Counties, Texas filed a lawsuit against us in Martin County District Court. These owners claimed that we breached certain leases by, among other things, exceeding permitted surface uses, failing to obtain required consents and failing to pay certain royalties due to them. We filed our answer to the lawsuit on September 10, 2018; shortly thereafter, we and the plaintiffs entered into settlement negotiations. Effective September 28, 2018, the parties executed a settlement agreement that provides for a dismissal of the lawsuit with prejudice.

Item 1A. Risk Factors

In addition to the information set forth in this Quarterly Report, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, ~~2017,~~2018, including those under the headings “Part I, Item 1. Business — Competition,” “— Marketing Arrangements” and “— Applicable Laws and Regulations,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, under the heading “Part II, Item 1A. Risk Factors,” and in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, under the heading “Part II, Item 1A. Risk Factors,” which risks could materially affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, ~~2017, and in our subsequent Quarterly Reports on Form 10-Q, other than the risk factor set forth below.~~2018. The risks described in our reports filed with the SEC are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

~~The payment of dividends will be at the discretion of our board of directors.~~

While the Company has announced plans to initiate a regular quarterly dividend in 2019, the payment and amount of future dividend payments, if any, are subject to declaration by our board of directors. Such payments will depend on various factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, restrictions imposed by applicable law, our taxable income, our operating expenses and other factors our board of directors deems relevant. The Company is under no obligation to make dividend payments and may cease such payments at any time in the future.

6152

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

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

Period

Total number of shares withheld (a)

Average price per share

Total number of shares purchased as part of publicly announced plans

Maximum number of shares that may yet be purchased under the plan

July 1, 2018 - July 31, 2018

214,586

$
149.47

-

August 1, 2018 - August 31, 2018

128

$
135.26

-

September 1, 2018 - September 30, 2018

77

$
143.68

-




(a) Represents shares that were withheld by us to satisfy tax withholding obligations of certain employees that arose upon the

lapse of restrictions on share-based awards.


Period		Total number of shares withheld (a)	Average price per share		Total number of shares purchased as part of publicly announced plans	Maximum number of shares that may yet be purchased under the plan

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


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

6253

Item 6. Exhibits

Exhibit No.		Exhibit

3.1		Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).

3.2		Fourth Amended and Restated Bylaws of Concho Resources Inc., as amended January 2, 2018 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on January 4, 2018, and incorporated herein by reference).

~~4.1~~10.1	**	~~Sixteenth Supplemental Indenture,~~Form of Performance Unit Award Agreement, dated ~~August 14, 2018, among Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee~~January 2, 2019 (filed as Exhibit ~~4.1~~10.2 to the Company’s Current Report on Form 8-K on ~~August 15, 2018,~~January 4, 2019, and incorporated herein by reference).
10.2	**	Form of Succession Restricted Stock Agreement, dated January 2, 2019 (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.3	**	Employment Agreement, dated January 1, 2019, by and between Concho Resources Inc. and J. Steve Guthrie (filed as Exhibit 10.8 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.4	**	Form of Indemnification Agreement, dated January 2, 2019, between Concho Resources Inc. and each of the officers and directors thereof (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.5	**	Form of Succession 3-Year Performance Unit Award Agreement, dated January 2, 2019, between Concho Resources Inc. and each of Messrs. Harper and Giraud (filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.6	**	Form of Succession 5-Year Performance Unit Award Agreement, dated January 2, 2019, between Concho Resources Inc. and each of Messrs. Harper and Giraud (filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.7	**	Executive Severance Plan, dated January 1, 2019, by and between Concho Resources Inc. and each of the officers thereof (filed as Exhibit 10.7 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
10.8	**	Form of Restricted Stock Agreement (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).
31.1	(a)	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

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

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

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

101.INS	(a)	XBRL Instance Document.

101.SCH	(a)	XBRL Schema Document.

101.CAL	(a)	XBRL Calculation Linkbase Document.

101.DEF	(a)	XBRL Definition Linkbase Document.

101.LAB	(a)	XBRL Labels Linkbase Document.

101.PRE	(a)	XBRL Presentation Linkbase Document.

(a) Filed herewith.

(b) Furnished herewith.

** Management contract or compensatory plan or arrangement.

6355

SIGNATURES

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

CONCHO RESOURCES INC.

Date:	~~October 31, 2018~~May 1, 2019	By	/s/ Timothy A. Leach

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


		By	/s/ ~~Jack F. Harper~~Brenda R. Schroer

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


		By	/s/ ~~Brenda R. Schroer~~Jacob P. Gobar

			~~Brenda R. Schroer~~Jacob P. Gobar
			~~Senior~~ Vice President and Chief Accounting Officer ~~and Treasurer~~
			(Principal Accounting Officer)

6456


		September 30,		December 31,
(in millions, except number of projects)		2018		2017

Capitalized exploratory well costs that have been capitalized for a period of one year		$	326	$	180
	or less
Capitalized exploratory well costs that have been capitalized for a period greater
	than one year		-		2
	Total capitalized exploratory well costs	$	326	$	182
Number of projects with exploratory well costs that have been capitalized for a period
	greater than one year		-		2


Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2018


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

Total operating revenues		$	-	$	1,192	$	-	$	-	$	1,192
Total operating costs and expenses			(626)		(791)		-		-		(1,417)
	Income (loss) from operations		(626)		401		-		-		(225)
Interest expense			(46)		-		-		-		(46)
Other, net			404		3		-		(404)		3
	Income (loss) before income taxes		(268)		404		-		(404)		(268)
Income tax benefit			69		-		-		-		69
	Net income (loss)	$	(199)	$	404	$	-	$	(404)	$	(199)

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2017


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

Total operating revenues		$	-	$	619	$	8	$	-	$	627
Total operating costs and expenses			(207)		(491)		(6)		-		(704)
	Income (loss) from operations		(207)		128		2		-		(77)
Interest expense			(39)		-		-		-		(39)
Loss on extinguishment of debt			(65)		-		-		-		(65)
Other, net			132		2		-		(132)		2
	Income (loss) before income taxes		(179)		130		2		(132)		(179)
Income tax benefit			66		-		-		-		66
	Net income (loss)	$	(113)	$	130	$	2	$	(132)	$	(113)


Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2018


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

Total operating revenues		$	-	$	3,079	$	5	$	-	$	3,084
Total operating costs and expenses			(794)		(1,294)		(3)		-		(2,091)
	Income (loss) from operations		(794)		1,785		2		-		993
Interest expense			(103)		-		-		-		(103)
Other, net			1,895		108		-		(1,895)		108
	Income before income taxes		998		1,893		2		(1,895)		998
Income tax expense			(225)		-		-		-		(225)
	Net income	$	773	$	1,893	$	2	$	(1,895)	$	773

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2017


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

Total operating revenues		$	-	$	1,798	$	8	$	-	$	1,806
Total operating costs and expenses			288		(837)		(6)		-		(555)
	Income from operations		288		961		2		-		1,251
Interest expense			(117)		(1)		-		-		(118)
Loss on extinguishment of debt			(66)		-		-		-		(66)
Other, net			982		20		-		(982)		20
	Income before income taxes		1,087		980		2		(982)		1,087
Income tax expense			(398)		-		-		-		(398)
	Net income	$	689	$	980	$	2	$	(982)	$	689


		Nine Months Ended September 30,
		2018				2017
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Lease operating expenses		$	388	$	5.73	$	278	$	5.47
Workover costs			28		0.42		15		0.29
	Total oil and natural gas production expenses	$	416	$	6.15	$	293	$	5.76