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, 2017~~

March 31, 2020

☐

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

For the transition period fromto

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)

(I.R.S. Employer Identification No.)

One Concho Center

600 West Illinois Avenue

Midland ~~Texas~~

Texas

79701

(Address of principal executive offices)

(Zip ~~code)~~

Code)

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

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, par value $0.001 per share

CXO

New York Stock Exchange

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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 o

☐

Non-accelerated filer ~~o (Do not check if a smaller reporting company)~~

☐

Smaller reporting company o

☐

Emerging growth company o

☐

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. o

☐

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

Number of shares of the registrant’s common stock outstanding at ~~October 30, 2017: 148,696,032~~April 27, 2020: 196,701,580 shares

Table of Contents

TABLE OF CONTENTS

Table of Contents

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, production, capital expenditures, liquidity and capital resources, the timing and success of specific projects, and outcomes and effects of ~~litigation, claims~~regulation and ~~disputes, derivative activities and potential financing.~~disputes. 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 ~~the uncertainty of~~ 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,~~1A. Risk Factors” in this Quarterly Report and in “Part I, Item ~~1A,~~1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, ~~2016,~~2019, as well as those factors summarized ~~below:~~

·below, many of which are beyond our control:

•declines in, or the sustained depression of, or increased volatility in the prices we receive for our oil and natural ~~gas;~~

·~~uncertainties about~~gas, or increases in the ~~estimated quantities~~differential between index oil or natural gas prices and prices received, including the recent dramatic decline of oil and natural gas ~~reserves;~~

·~~drilling, completion and operating risks;~~

·~~the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing and the export of oil and natural gas;~~

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

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

·prices;

•risks related to and the ~~concentration~~impact of ~~our operations in~~actual or anticipated pandemics such as the ~~Permian Basin of southeast New Mexico and west Texas;~~

·novel coronavirus (“COVID-19”) pandemic;

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

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

•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 the capital markets and 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;

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

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

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

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

•competition in the oil and natural gas industry;

•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 well spacing and a high concentration of activity;

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

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

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

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

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

•risks related to the recruitment and retention of qualified personnel in the Permian Basin;

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

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

·~~risks and liabilities associated with acquired properties or businesses;~~

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

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

·~~the impact of potential changes in our credit ratings;~~

·cybersecurity risks, such as those involving unauthorized access, malicious software, data privacy breaches by employees or others with authorized access, cyber or phishing-attacks, ransomware and other security issues;

·~~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.~~

program.

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.

iii

Table of Contents

PART I– FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

~~iii~~

Table of Contents

Concho Resources Inc.

Consolidated Balance Sheets

~~Unaudited~~

September 30,

December 31,
(in millions, except share and per share amounts)

2017

2016
Assets
Current assets:

Cash and cash equivalents

$
-

$
53

Accounts receivable, net of allowance for doubtful accounts:

Oil and natural gas

271

220

Joint operations and other

223

238

Derivative instruments

4

4

Prepaid costs and other

37

31


Total current assets

535

546
Property and equipment:

Oil and natural gas properties, successful efforts method

20,754

18,476

Accumulated depletion and depreciation

(8,167)

(7,390)

Total oil and natural gas properties, net

12,587

11,086

Other property and equipment, net

232

216

Total property and equipment, net

12,819

11,302
Funds held in escrow

-

43
Deferred loan costs, net

14

11
Intangible asset - operating rights, net

24

24
Inventory

15

16
Noncurrent derivative instruments

28

-
Other assets

47

177

Total assets

$
13,482

$
12,119
Liabilities and Stockholders’ Equity
Current liabilities:

Accounts payable - trade

$
36

$
28

Bank overdrafts

68

-

Revenue payable

135

132

Accrued drilling costs

381

359

Derivative instruments

37

82

Other current liabilities

153

152


Total current liabilities

810

753
Long-term debt

2,738

2,741
Deferred income taxes

1,150

766
Noncurrent derivative instruments

6

96
Asset retirement obligations and other long-term liabilities

147

140
Commitments and contingencies (Note 9)

Stockholders’ equity:

Common stock, $0.001 par value; 300,000,000 authorized; 149,297,932 and

146,488,685 shares issued at September 30, 2017 and December 31, 2016, respectively

-

-

Additional paid-in capital

7,125

6,783

Retained earnings

1,573

884

Treasury stock, at cost; 597,551 and 429,708 shares at September 30, 2017 and

December 31, 2016, respectively

(67)

(44)


Total stockholders’ equity

8,631

7,623

Total liabilities and stockholders’ equity

$
13,482

$
12,119

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

Unaudited


(in millions, except share and per share amounts)	March 31, 2020		December 31, 2019
Assets
Current assets:
Cash and cash equivalents	$	165	$	70
Accounts receivable, net:
Oil and natural gas	472		584
Joint operations and other	298		304
Inventory	25		30
Derivative instruments	1,241		6
Prepaid costs and other	59		61
Total current assets	2,260		1,055
Property and equipment:
Oil and natural gas properties, successful efforts method	26,644		28,785
Accumulated depletion and depreciation	(16,182)		(7,895)
Total oil and natural gas properties, net	10,462		20,890
Other property and equipment, net	449		437
Total property and equipment, net	10,911		21,327
Deferred loan costs, net	6		7
Goodwill	—		1,917
Intangible assets, net	17		17
Noncurrent derivative instruments	225		11
Other assets	195		398
Total assets	$	13,614	$	24,732
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable - trade	$	80	$	53

Revenue payable	260		268
Accrued drilling costs	382		386
Derivative instruments	—		112
Other current liabilities	324		363
Total current liabilities	1,046		1,182
Long-term debt	3,956		3,955
Deferred income taxes	87		1,654
Noncurrent derivative instruments	—		7
Asset retirement obligations and other long-term liabilities	146		152
Commitments and contingencies (Note 7)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 197,930,291 and 198,863,681 shares issued at March 31, 2020 and December 31, 2019, respectively	—		—
Additional paid-in capital	14,526		14,608
Retained earnings (accumulated deficit)	(5,997)		3,320
Treasury stock, at cost; 1,225,682 and 1,175,026 shares at March 31, 2020 and December 31, 2019, respectively	(150)		(146)
Total stockholders’ equity	8,379		17,782
Total liabilities and stockholders’ equity	$	13,614	$	24,732

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

Table of Contents

Concho Resources Inc.

Consolidated Statements of Operations

~~Unaudited~~

Three Months Ended

Nine Months Ended

September 30,

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

2017

2016

2017

2016

Operating revenues:

Oil sales

$
498

$
348

$
1,461

$
929

Natural gas sales

129

82

345

181

Total operating revenues

627

430

1,806

1,110
Operating costs and expenses:

Oil and natural gas production

106

71

293

240

Production and ad valorem taxes

48

33

140

89

Exploration and abandonments

7

10

42

54

Depreciation, depletion and amortization

284

299

848

890

Accretion of discount on asset retirement obligations

2

2

6

5

Impairments of long-lived assets

-

-

-

1,525

General and administrative (including non-cash stock-based compensation of

$17 and $15 for the three months ended September 30, 2017

and 2016, respectively, and $43 for each of the nine months

ended September 30, 2017 and 2016)

64

53

180

160

(Gain) loss on derivatives

206

(41)

(289)

176

(Gain) loss on disposition of assets, net

(13)

1

(667)

(109)

Total operating costs and expenses

704

428

553

3,030
Income (loss) from operations

(77)

2

1,253

(1,920)
Other income (expense):

Interest expense

(39)

(53)

(118)

(162)

Loss on extinguishment of debt

(65)

(28)

(66)

(28)

Other, net

2

(2)

18

(9)

Total other expense

(102)

(83)

(166)

(199)
Income (loss) before income taxes

(179)

(81)

1,087

(2,119)

Income tax (expense) benefit

66

30

(398)

782
Net income (loss)

$
(113)

$
(51)

$
689

$
(1,337)
Earnings per share:

Basic net income (loss)

$
(0.77)

$
(0.38)

$
4.64

$
(10.18)

Diluted net income (loss)

$
(0.77)

$
(0.38)

$
4.63

$
(10.18)

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

Unaudited


	Three Months Ended March 31,
(in millions, except per share amounts)	2020		2019
Operating revenues:
Oil sales	$	872	$	935
Natural gas sales	50		169
Total operating revenues	922		1,104
Operating costs and expenses:
Oil and natural gas production	164		174
Production and ad valorem taxes	74		86
Gathering, processing and transportation	50		26
Exploration and abandonments	2,719		47
Depreciation, depletion and amortization	524		465
Accretion of discount on asset retirement obligations	2		3
Impairments of long-lived assets	7,772		—
Impairments of goodwill	1,917		—
General and administrative (including non-cash stock-based compensation of $18 and $24 for the three months ended March 31, 2020 and 2019, respectively)	69		91
(Gain) loss on derivatives	(1,769)		1,059
(Gain) loss on disposition of assets, net	5		(1)
Transaction costs	2		—
Total operating costs and expenses	11,529		1,950
Loss from operations	(10,607)		(846)
Other income (expense):
Interest expense	(42)		(47)
Other, net	(195)		4
Total other expense	(237)		(43)
Loss before income taxes	(10,844)		(889)
Income tax benefit	1,567		194
Net loss	$	(9,277)	$	(695)
Earnings per share:
Basic net loss	$	(47.49)	$	(3.49)
Diluted net loss	$	(47.49)	$	(3.49)

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

Table of Contents

Concho Resources Inc.

Consolidated ~~Statement~~Statements of Stockholders’ Equity

~~Unaudited~~

Common Stock

Additional

Total

Issued

Paid-in

Retained

Treasury Stock

Stockholders’
(in millions, except share data)

Shares

Amount

Capital

Earnings

Shares

Amount

Equity

(in thousands)

(in thousands)

BALANCE AT DECEMBER 31, 2016

146,489

$
-

$
6,783

$
884

430

$
(44)

$
7,623

Adoption of ASU No. 2016-09 (Note 2)

-

-

8

-

-

-

8
BALANCE AT JANUARY 1, 2017

146,489

-

6,791

884

430

(44)

7,631

Net income

-

-

-

689

-

-

689

Common stock issued in business combinations

2,177

-

291

-

-

-

291

Stock options exercised

20

-

-

-

-

-

-

Grants of restricted stock

445

-

-

-

-

-

-

Performance unit share conversion

249

-

-

-

-

-

-

Cancellation of restricted stock

(82)

-

-

-

-

-

-

Stock-based compensation

-

-

43

-

-

-

43

Purchase of treasury stock

-

-

-

-

168

(23)

(23)
BALANCE AT SEPTEMBER 30, 2017

149,298

$
-

$
7,125

$
1,573

598

$
(67)

$
8,631

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

Unaudited


















	Three Months Ended March 31, 2020
	Common Stock Issued					Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Treasury Stock				Total Stockholders’ Equity
(in millions, except share data)	Shares	Amount								Shares		Amount
	(in thousands)								(in thousands)
BALANCE AT DECEMBER 31, 2019	198,864	$	—	$	14,608	$	3,320	1,175		$	(146)	$	17,782
Adoption of ASU No. 2016-13 (Note 2)	—	—		—		(1)		—		—		(1)
BALANCE AT JANUARY 1, 2020	198,864	—		14,608		3,319		1,175		(146)		17,781
Net loss	—	—		—		(9,277)		—		—		(9,277)
Common stock repurchased and retired	(1,126)	—		(100)		—		—		—		(100)
Common stock dividends ($0.20 per share)	—	—		—		(39)		—		—		(39)
Grants of restricted stock	175	—		—		—		—		—		—
Performance unit share conversion	41	—		—		—		—		—		—
Cancellation of restricted stock	(24)	—		—		—		—		—		—
Stock-based compensation	—	—		18		—		—		—		18
Purchase of treasury stock	—	—		—		—		51		(4)		(4)
BALANCE AT MARCH 31, 2020	197,930	$	—	$	14,526	$	(5,997)	1,226		$	(150)	$	8,379


















	Three Months Ended March 31, 2019
	Common Stock Issued					Additional Paid-in Capital		Retained Earnings		Treasury Stock				Total Stockholders’ Equity
(in millions, except share data)	Shares	Amount								Shares		Amount
	(in thousands)								(in thousands)
BALANCE AT DECEMBER 31, 2018	201,289	$	—	$	14,773	$	4,126	1,032		$	(131)	$	18,768
Net loss	—	—		—		(695)		—		—		(695)
Common stock dividends ($0.125 per share)	—	—		—		(25)		—		—		(25)
Grants of restricted stock	235	—		—		—		—		—		—
Performance unit share conversion	246	—		—		—		—		—		—
Cancellation of restricted stock	(15)	—		—		—		—		—		—
Stock-based compensation	—	—		24		—		—		—		24
Purchase of treasury stock	—	—		—		—		124		(13)		(13)
BALANCE AT MARCH 31, 2019	201,755	$	—	$	14,797	$	3,406	1,156		$	(144)	$	18,059

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

Table of Contents

Concho Resources Inc.

Consolidated Statements of Cash Flows

~~Unaudited~~

Nine Months Ended


September 30,
(in millions)

2017

2016
CASH FLOWS FROM OPERATING ACTIVITIES:

Net income (loss)

$
689

$
(1,337)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, depletion and amortization

848

890

Accretion of discount on asset retirement obligations

6

5

Impairments of long-lived assets

-

1,525

Exploration and abandonments, including dry holes

29

47

Non-cash stock-based compensation expense

43

43

Deferred income taxes

392

(768)

Gain on disposition of assets, net

(667)

(109)

(Gain) loss on derivatives

(289)

176

Net settlements received from derivatives

126

582

Loss on extinguishment of debt

66

28

Other non-cash items

1

10

Changes in operating assets and liabilities, net of acquisitions and dispositions:

Accounts receivable

(61)

61

Prepaid costs and other

(1)

7

Inventory

(1)

2

Accounts payable

7

9

Revenue payable

5

(57)

Other current liabilities

(8)

(95)

Net cash provided by operating activities

1,185

1,019
CASH FLOWS FROM INVESTING ACTIVITIES:

Capital expenditures on oil and natural gas properties

(1,958)

(927)

Additions to property, equipment and other assets

(34)

(20)

Proceeds from the disposition of assets

803

296

Direct transaction costs for disposition of assets

(18)

-

Funds held in escrow

-

(81)

Contributions to equity method investments

-

(51)



Net cash used in investing activities

(1,207)

(783)
CASH FLOWS FROM FINANCING ACTIVITIES:

Proceeds from issuance of debt

2,267

-

Payments of debt

(2,255)

(600)

Debt extinguishment costs

(63)

(21)

Excess tax deficiency from stock-based compensation (Note 2)

-

(1)

Net proceeds from issuance of common stock

-

1,327

Payments for loan costs

(25)

-

Purchase of treasury stock

(23)

(11)

Increase in bank overdrafts

68

-



Net cash provided by (used in) financing activities

(31)

694



Net increase (decrease) in cash and cash equivalents

(53)

930
Cash and cash equivalents at beginning of period

53

229
Cash and cash equivalents at end of period

$
-

$
1,159
NON-CASH INVESTING AND FINANCING ACTIVITIES:

Issuance of common stock for business combinations

$
291

$
231

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

Unaudited


	Three Months Ended March 31,
(in millions)	2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(9,277)	$	(695)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	524		465
Accretion of discount on asset retirement obligations	2		3
Impairments of long-lived assets	7,772		—
Impairments of goodwill	1,917		—
Exploration and abandonments	2,713		38
Non-cash stock-based compensation expense	18		24
Deferred income taxes	(1,567)		(194)
Net (gain) loss on disposition of assets and other non-operating items	5		(1)
(Gain) loss on derivatives	(1,769)		1,059
Net settlements received from derivatives	201		—
Other	205		2
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable	122		(111)
Prepaid costs and other	2		9
Inventory	5		—
Accounts payable	27		11
Revenue payable	(8)		8
Other current liabilities	(56)		5
Net cash provided by operating activities	836		623
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and natural gas properties	(556)		(918)
Changes in working capital associated with oil and natural gas property additions	(1)		33
Acquisitions of oil and natural gas properties	(20)		(5)
Additions to property, equipment and other assets	(19)		(15)
Proceeds from the disposition of assets	—		5

Direct transaction costs for asset acquisitions and dispositions	—		(2)

Net cash used in investing activities	(596)		(902)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	345		1,112
Payments on credit facility	(345)		(739)




Payment of common stock dividends	(39)		(25)
Purchases of treasury stock	(4)		(13)
Purchases of common stock under share repurchase program	(100)		—
Decrease in book overdrafts	—		(54)
Other	(2)		(2)
Net cash provided by (used in) financing activities	(145)		279
Net increase in cash and cash equivalents	95		—
Cash and cash equivalents at beginning of period	70		—
Cash and cash equivalents at end of period	$	165	$	—

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

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2017~~

March 31, 2020

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~~(the “Company”), is an independent oil and natural gas company engaged in the acquisition, development, exploration and production of oil and natural gas ~~properties~~properties. The Company's operations are primarily ~~located~~focused in the Permian Basin of ~~southeast~~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, 2019 (“2019 Form 10-K”).

Principles of consolidation.The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The Company consolidates the financial statements of these entities. The consolidated financial statements also include the accounts of a variable interest entity (“VIE”) where the Company is the primary beneficiary of the arrangements. See Note 4 for additional information regarding the circumstances surrounding the VIE. All material intercompany balances and transactions have been eliminated.

Reclassifications.Certain prior period amounts have been reclassified to conform to the ~~2017~~2020 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 ~~exchanges,~~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, ~~2016~~2019 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~~2019 Form ~~10-K for the year ended December 31, 2016.~~

~~Cash equivalents.~~ 10-K.

Accounts receivable. The Company ~~considers all cash on hand, depository accounts held by banks, money market accounts~~sells oil and ~~investments~~natural gas to various customers and participates with ~~an original maturity~~other parties in the drilling, completion and operation of ~~three months or less to be cash equivalents. The Company’s cash~~oil and cash equivalents are held in financial institutions in amounts that 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. At December 31, 2016, the majoritynatural gas wells.

One area of the Company’s ~~cash~~exposure to credit risk is through the sale of its oil and natural gas production. The Company monitors this exposure primarily by reviewing credit ratings, financial statements and payment history. The Company extends credit terms based on its evaluation of each counterparty’s creditworthiness. Oil and natural gas sales receivables are generally unsecured and typically received from the purchaser one to two months after production. The Company had an allowance for expected credit losses of $6 million at March 31, 2020, which was ~~invested~~primarily based on a historical loss rate. The Company’s allowance for doubtful accounts at December 31, 2019 was $5 million.

Joint interest receivables are generally secured pursuant to the operating agreement between or among the co-owners of the operated property. The Company has the right to realize the receivables through netting of anticipated future production revenues. The allowance for expected credit losses for these receivables is primarily based on a historical loss rate. The Company’s assessment of the creditworthiness of the joint interest owners is another factor that is considered in ~~stable value government money market funds.~~

developing its allowance for expected credit losses. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written-off against the allowance for expected credit losses only after all collection

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2017~~

March 31, 2020

Unaudited

attempts have been exhausted. The Company had an allowance for expected credit losses of $2 million at March 31, 2020. The Company had an allowance for doubtful accounts of $2 million at December 31, 2019.

The Company considers forecasts of future economic conditions in the estimate of its expected credit losses, in particular whether there is an increase in the probability that the Company’s counterparties are unable to pay their obligations when due, and adjusts its allowance for expected credit losses, when necessary.

Equity method investments.~~At December 31, 2016,~~ The Company holds membership interests in certain entities and accounts for these investments using the equity method of accounting:

•The Company ~~owned~~owns a 50 percent membership interest in Beta Holding Company, LLC, a midstream joint venture ~~Alpha Crude Connector, LLC (“ACC”), that operated~~formed to construct a crude oil gathering ~~and transportation~~ system in the ~~Northern Delaware~~Midland Basin. ~~In February 2017, the~~

•The Company ~~closed on the divestiture of its ownership~~owns a 20 percent membership interest in ~~ACC. See Note 4 for additional information regarding~~Solaris Midstream Holdings, LLC, an entity that owns and operates water gathering, transportation, disposal, recycling and storage infrastructure assets in the ~~disposition of ACC.~~

Permian Basin.

•The Company ~~accounted for~~owns a preferred membership interest in WaterBridge Operating LLC, an entity that operates and manages various water infrastructure assets located in the Permian Basin.

The Company includes its ~~investment in ACC under the~~ equity method ~~of accounting for investments in unconsolidated affiliates. The Company’s net~~ investment ~~in ACC was approximately $129 million at December 31, 2016, and was included~~balance in other assets inon the ~~Company’s~~ consolidated balance ~~sheet. Gains~~sheets. The Company records its share of equity investment earnings and losses ~~incurred from the Company’s equity investment in ACC were recorded~~ in other income (expense) ~~in its~~on the consolidated statements of operations.

The Company owns 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. The Company accounts for its investment in Oryx under therecorded equity method investment losses of ~~accounting~~$202 million for ~~investments in unconsolidated affiliates.~~the three months ended March 31, 2020. The ~~Company’s net~~loss during the first quarter of 2020 was primarily due to an other than temporary impairment of an equity method investment ~~in Oryx was approximately $47~~of $204 million, ~~and $42 million at September 30, 2017 and December 31, 2016, respectively, and~~which is also included in other ~~assets~~cash flows from operating activities on the consolidated statement of cash flows.

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 ~~Company’s consolidated balance sheets. Gains~~degree of probability and ~~losses incurred from the Company’s equity investment in Oryx are recorded in other income (expense)~~range of possible loss for potential accrual in its consolidated ~~statements~~financial statements. The amount of ~~operations.~~

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 7 for additional information.

Revenue recognition. ~~Oil and natural gas revenues are recorded at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead.~~ The Company ~~follows~~recognizes revenues from the sales ~~method~~ of ~~accounting for~~ oil and natural gas ~~sales, recognizing revenues based~~to its customers and presents them disaggregated on the Company’s ~~actual proceeds~~consolidated statements of operations. All revenues are recognized in the geographical region of the Permian Basin.

The Company enters into contracts with customers to sell its oil and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with Customers,” (“ASC 606”). Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to ~~purchasers.~~receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. At March 31, 2020 and December 31, 2019, the Company had net receivables related to contracts with customers of $320 million and $584 million, respectively.

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

Natural Gas Contracts. The majority of the Company’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. The natural gas is sold under (i) percentage of proceeds processing contracts, (ii) fee-based contracts or (iii) a hybrid of percentage of proceeds and fee-based contracts. Under the majority of the Company’s contracts, the purchaser gathers the natural gas in the field where it is produced and transports it via pipeline to natural gas processing plants where natural gas liquid products are extracted. The natural gas liquid products

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2020

Unaudited

and remaining residue gas are then sold by the purchaser. Under the percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, the Company receives a percentage of the value for the extracted liquids and the residue gas. Under the fee-based contracts, the Company receives natural gas liquids and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those activities, revenue is recognized on a gross basis, and the related costs are classified in gathering, processing and transportation on the Company’s consolidated statements of operations.

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

General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and records such reimbursements as reductions ofto general and administrative expense. ~~The Company earned reimbursements of approximately~~Such fees totaled $5 million and $4 million for ~~each of~~ the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016 and approximately $12 million~~2019, respectively.

Goodwill. Goodwill is assessed for ~~each~~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 ~~nine months ended September 30, 2017~~reporting unit 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. The reporting unit’s fair value is the Company’s enterprise value calculated as the combined market capitalization of the Company’s equity plus a control premium and ~~2016.~~

the fair value of the Company’s long-term debt. 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.

The Company performed an impairment test at March 31, 2020 due to the recent significant decline in oil and natural gas prices as well as the reduced demand for oil and natural gas as a result of the COVID-19 pandemic and other supply factors during the first quarter of 2020. As a result, the Company impaired its entire goodwill balance of $1.9 billion. The impairment was due to the significant decline in the Company’s enterprise value. To estimate the fair value of the reporting unit at March 31, 2020, the Company used an average stock price of $41.63. The period over which this average stock price was calculated was shortened for the announcement of the COVID-19 pandemic to include the impact of the recent decline in oil and natural gas prices on the Company’s common stock. In addition, the Company’s control premium was based on the median control premium of recent transactions in the Company’s industry.

Recently adopted accounting pronouncements. In March 2020, the Securities and Exchange Commission (“SEC”) adopted final rules that amend the financial disclosure requirements for subsidiary issuers and guarantors of registered debt securities in Rule 3-10 of Regulation S-X. The ~~Company adopted Accounting Standards Update (“ASU”) No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvements~~amended rules, which can be found under new Rule 13-01 of Regulation S-X, narrow the circumstances that require separate financial statements of subsidiary issuers and guarantors and streamline the alternative disclosures required in lieu of those statements. The amended rules allow the registrants, among other things, to ~~Employee Share-based Payment Accounting,”~~disclose summarized financial information of the issuer and guarantors on ~~January 1, 2017.~~a combined basis and to present only the most recently completed fiscal year and subsequent year-to-date interim period. The ~~adoption did~~rule allows the parent company to omit summarized financial information if it is not ~~have an impact on prior period~~material, or if assets, liabilities, and results of operations of the combined issuers and guarantors of the security are not materially different than the amounts in the parent company’s consolidated financial statements. The Company elected to account for forfeitures of share-based payments as they occur. At December 31, 2016, the Company had not recorded compensation expense of approximately $8 million based on forecasted forfeitures nor the associated deferred tax benefit of approximately $3 million.rule is effective January 4, 2021, but earlier compliance is permitted. The Company ~~recognized all excess tax benefits not previously recorded, which totaled approximately $5 million at December 31, 2016. Upon adoption,~~early adopted the ~~Company recorded a cumulative-effect adjustment, which decreased retained earnings by less than $1 million, increased additional paid-in capital by approximately $8 million,~~rule in the first quarter of 2020 and ~~decreased net deferred income taxes by approximately $8 million. The Company elected~~chose to ~~prospectively classify excess tax benefits and deficiencies~~omit the summarized financial information as ~~operating activities on~~ the ~~consolidated~~combined financial statements of ~~cash flows~~the issuer and ~~will prospectively record those excess tax benefits and deficiencies as discrete items~~guarantors were not materially different than the amounts in the ~~income tax provision in the~~Company’s consolidated statements of operations. Under the new standard, for the nine months ended September 30, 2017, the Company recorded excess tax benefits of approximately $6 million as offsets to the Company’s income tax provision. Also under the new standard, for the three and nine months ended September 30, 2017, the Company recorded forfeitures of share-based payments of approximately $1 million and $7 million, respectively.

~~New accounting pronouncements issued but not yet adopted.~~ financial statements.

In ~~May 2014,~~June 2016, the Financial Accounting Standards Board ~~(the “FASB”~~(“FASB”) issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

~~recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.~~

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU No. 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. The Company expects to use the modified retrospective method to adopt the standard, meaning the cumulative effect of initially applying the standard will be recognized with an adjustment to retained earnings on January 1, 2018. The Company has substantially completed its internal evaluation of the adoption of this standard, which included a review of all revenue-related contracts with customers and the application of the new revenue recognition model against those contracts. The Company is also updating its revenue recognition policy to conform to the new standard. The Company also expects to expand its revenue recognition related disclosure. Including those changes previously discussed, the Company does not expect this new guidance will have a material impact on its consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for financing and operating leases. Lease expense recognition on the consolidated statements of operations will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company does not plan to early adopt the standard. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services, well equipment and drilling rigs. The Company is currently in the process of reviewing all contracts that could be applicable to this new guidance. The Company believes this new guidance will have a moderate impact to its consolidated balance sheets due to the recognition of right-of-use assets and lease liabilities that are not currently recognized under currently applicable guidance.

~~In June 2016, the FASB issued ASU~~Accounting Standards Update (“ASU”) No. 2016-13, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial ~~Instruments,”~~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. The adoption of this guidance on January 1, 2020 did not have a material impact on the Company’s consolidated financial statements or related disclosures. Oil and natural gas sales receivables and joint interest receivables are the primary financial assets that are within the scope of the new guidance. A loss-rate method is applied to these receivables to estimate credit losses. The Company recognized a tax effected $1 million non-cash cumulative effect adjustment to retained earnings on its

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2020

Unaudited

opening consolidated balance sheet at January 1, 2020 to record an allowance for expected credit losses associated with the Company’s oil and natural gas sales receivables.

New accounting pronouncements issued but not yet adopted. In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 840): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate (“LIBOR”)) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted as a continuation of the existing contract. This ASU was effective upon the issuance and its optional relief can be applied through December 31, 2022. The Company will consider this optional guidance prospectively, if applicable.

In December 2019, the FASB issued ASU No. 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes” (“ASU 2019-12”), which simplifies various aspects of the income tax accounting guidance in ASC 740, including requirements related to the following: (i) hybrid tax regimes; (ii) the tax basis step-up in goodwill obtained in a transaction that is not a business combination; (iii) separate financial statements of entities not subject to tax; (iv) the intraperiod tax allocation exception to the incremental approach; (v) ownership changes in investments - changes from a subsidiary to an equity method investment (and vice versa); (vi) interim-period accounting for enacted changes in tax laws; and (vii) the year-to-date loss limitation in interim-period tax accounting. ASU 2019-12 is effective for fiscal years beginning after December 15, ~~2019,~~2020, and interim periods within those fiscal years and early adoption is ~~allowed~~permitted. If an entity early adopts these amendments in an interim period, it should reflect any adjustments as of the beginning of the annual period that includes that interim period. In addition, an entity that elects to early ~~as fiscal years beginning after December 15, 2018. The Company does not believe this new guidance will have a material impact on its consolidated financial statements.~~

~~In January 2017, the FASB issued~~adopt ASU ~~No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” with the objective of adding guidance~~2019-12 is required to assist in evaluating whether transactions should be accounted for as asset acquisitions or as business combinations. The guidance provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantiallyadopt all of the ~~fair value of~~amendments in the acquired assets is concentrated in a single asset or a group of similar assets, the set is not a business. If the screen is not met, to be considered a business, the set must include an input and a substantive process that together significantly contribute to the ability to create output. This new guidance is effective for annual periods beginning after December 15, 2017, and early adoption is allowed.same period. The Company is ~~evaluating~~currently assessing the ~~impact this new guidance~~effect that ASU 2019-12 will have on its ~~consolidated~~ financial ~~statements.~~

position, results of operations and disclosures.

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

Note 3. ~~Exploratory well costs~~

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. 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 progress assessing the reserves and the economic and operating viability of the project.The capitalized exploratory well costs are carried in unproved oil and natural gas properties. See Note 15 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, 2017:~~

Nine Months Ended
(in millions)

September 30, 2017

Beginning capitalized exploratory well costs

$
151

Additions to exploratory well costs pending the determination of proved reserves

255

Reclassifications due to determination of proved reserves

(136)
Ending capitalized exploratory well costs

$
270

~~The following table provides an aging at September 30, 2017 and December 31, 2016 of capitalized exploratory well costs based on the date drilling was completed:~~

September 30,

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

2017

2016

Capitalized exploratory well costs that have been capitalized for a period of one year or less

$
266

$
141
Capitalized exploratory well costs that have been capitalized for a period greater than one year


4


10

Total capitalized exploratory well costs

$
270

$
151
Number of projects with exploratory well costs that have been capitalized for a period greater

than one year

4

8

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

~~Note 4.~~ ~~Acquisitions and divestitures~~

~~Midland Basin acquisition.~~In July 2017, the Company completed an acquisition in the Midland Basin. As consideration for the acquisition, the Company paid approximately $595 million in cash. The acquisition is subject to customary post-closing adjustments.

Concurrent with the acquisition, the Company entered into 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 (the “Code”). In connection with the Reverse 1031 Exchange, the Company assigned the ownership of the oil and natural gas properties acquired to a VIE formed by an exchange accommodation titleholder. The Company operates the properties pursuant to a management agreement with the VIE. At September 30, 2017, the Company was determined to be the primary beneficiary of the VIE, as the Company had the ability to control the activities that most significantly impact the VIE’s economic performance. The assets currently held by the VIE attributable to the acquisition will be conveyed to the Company or one of its subsidiaries, and the VIE structure will terminate, upon the earlier of (i) the completion of the Reverse 1031 Exchange or (ii) the expiration of the time allowed by the treasury regulations and published Internal Revenue Service guidance to complete the Reverse 1031 Exchange, which is 180 days from commencement. At September 30, 2017, the VIE’s total assets and liabilities included in the Company’s consolidated balance sheet were approximately $607 million and $605 million, respectively.

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

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

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

~~Note 5.~~Stock incentive plan

The ~~Company’s 2015~~Company's 2019 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.

The holders of unvested restricted stock awards have voting rights and the right to receive dividends. Performance units generally vest over a period of three years, with the exception of certain performance unit awards granted to certain officers during 2019 that have either a three-year performance period or a five-year performance period that, upon vesting, will convert into a restricted stock award with the number of shares determined based upon performance criteria.

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

A summary of the Company’s ~~Stock Incentive~~restricted stock shares and performance unit activity under the Plan ~~activity~~ for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 is presented below:


	Restricted Stock Shares		Performance Units
Outstanding at December 31, 2019	1,485,352		324,437
Awards granted (a)	174,722		185,301
Awards canceled / forfeited	(23,460)		(10,232)
Lapse of restrictions	(147,022)		(4,704)
Outstanding at March 31, 2020	1,489,592		494,802

(a) Weighted average grant date fair value per share/unit	$	87.17	$	126.30

Table of Contents

Restricted

Stock

Performance

Stock Shares

Options

Units

Outstanding at December 31, 2016


1,157,270

20,000

331,526

Awards granted (a)


445,384

-

108,398

Options exercised


-

(20,000)

-

Awards cancelled / forfeited


(82,200)

-

(43,333)

Lapse of restrictions

(389,965)

-

-

Outstanding at September 30, 2017

1,130,489

-

396,591

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

$
121.77

$
-

$
183.48



Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2020

Unaudited

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, 2017:~~

March 31, 2020:

(in millions)

Remaining 2017

$
17
2018


47
2019


25
Thereafter

8

Total

$
97


(in millions)
Remaining 2020	$	55
2021	47
2022	22
2023	3
2024	1
2025	1
Thereafter	1
Total	$	130

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

Note 6. 4. 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 1:1: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 2:2: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 3:3: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.

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2017~~

March 31, 2020

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, 2017~~March 31, 2020 and December 31, ~~2016:~~

2019:


			September 30, 2017				December 31, 2016
			Carrying		Fair		Carrying		Fair
(in millions)	(in millions)		Value		Value		Value		Value		(in millions)	March 31, 2020							December 31, 2019
(in millions)											(in millions)			Carrying Value		Fair Value			Carrying Value		Fair Value
(in millions)											Assets:
Derivative instruments											Derivative instruments	$	1,466	$	1,466		$	17	$	17

Liabilities:											Liabilities:
Derivative instruments											Derivative instruments	$	—	$	—		$	119	$	119
Credit facility											Credit facility	$	—	$	—		$	—	$	—
$600 million 4.375% senior notes due 2025 (a)											$600 million 4.375% senior notes due 2025 (a)	$	595	$	512		$	595	$	620
$1,000 million 3.75% senior notes due 2027 (a)											$1,000 million 3.75% senior notes due 2027 (a)	$	990	$	825		$	990	$	1,054
$1,000 million 4.3% senior notes due 2028 (a)											$1,000 million 4.3% senior notes due 2028 (a)	$	989	$	918		$	989	$	1,091
$800 million 4.875% senior notes due 2047 (a)											$800 million 4.875% senior notes due 2047 (a)	$	790	$	615		$	789	$	941
$600 million 4.85% senior notes due 2048 (a)											$600 million 4.85% senior notes due 2048 (a)	$	592	$	491		$	592	$	697
	Assets:
		Derivative instruments	$	32	$	32	$	4	$	4

	Liabilities:
		Derivative instruments	$	43	$	43	$	178	$	178
		Credit facility	$	368	$	368	$	-	$	-
		$600 million 5.5% senior notes due 2022 (a)	$	-	$	-	$	594	$	620
		$1,550 million 5.5% senior notes due 2023 (a)	$	-	$	-	$	1,555	$	1,621
		$600 million 4.375% senior notes due 2025 (a)	$	593	$	632	$	592	$	599
		$1,000 million 3.75% senior notes due 2027 (a)	$	988	$	1,006	$	-	$	-
		$800 million 4.875% senior notes due 2047 (a)	$	789	$	834	$	-	$	-


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

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

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

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

Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification,even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016.~~2019. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.

September 30, 2017

Fair Value Measurements Using

Net

Quoted Prices

Gross

Fair Value

in Active

Significant

Amounts

Presented

Markets for

Other

Significant

Offset in the

in the

Identical

Observable

Unobservable

Consolidated

Consolidated

Assets

Inputs

Inputs

Total

Balance

Balance
(in millions)
(Level 1)

(Level 2)

(Level 3)

Fair Value

Sheet

Sheet

Assets:

Current:

Commodity derivatives

$
-

$
35

$
-

$
35

$
(31)

$
4

Noncurrent:

Commodity derivatives

-


44


-


44


(16)


28

Liabilities:

Current:

Commodity derivatives

-

(68)

-

(68)

31

(37)

Noncurrent:

Commodity derivatives

-


(22)


-


(22)


16


(6)

Net derivative instruments

$
-

$
(11)

$
-

$
(11)

$
-

$
(11)

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2017~~

~~Unaudited~~

December 31, 2016

Fair Value Measurements Using

Net

Quoted Prices

Gross

Fair Value

in Active

Significant

Amounts

Presented

Markets for

Other

Significant

Offset in the

in the

Identical

Observable

Unobservable

Consolidated

Consolidated

Assets

Inputs

Inputs

Total

Balance

Balance
(in millions)
(Level 1)

(Level 2)

(Level 3)

Fair Value

Sheet

Sheet

Assets:

Current:

Commodity derivatives

$
-

$
59

$
-

$
59

$
(55)

$
4

Noncurrent:

Commodity derivatives

-


-


-


-


-


-

Liabilities:

Current:

Commodity derivatives

-


(137)


-


(137)


55


(82)

Noncurrent:

Commodity derivatives

-


(96)


-


(96)


-


(96)

Net derivative instruments

$
-

$
(174)

$
-

$
(174)

$
-

$
(174)

March 31, 2020

Unaudited


March 31, 2020
(in millions)	Fair Value Measurements Using
			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value			Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
Assets:
Current:
Commodity derivatives	$	—		$	1,277		$	—		$	1,277		$	(36)		$	1,241
Noncurrent:
Commodity derivatives	—			262			—			262			(37)			225

Liabilities:
Current:
Commodity derivatives	—			(36)			—			(36)			36			—
Noncurrent:
Commodity derivatives	—			(37)			—			(37)			37			—

Net derivative instruments	$	—		$	1,466		$	—		$	1,466		$	—		$	1,466


December 31, 2019
	Fair Value Measurements Using
(in millions)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Gross Amounts Offset in the Consolidated Balance Sheet		Net Fair Value Presented in the Consolidated Balance Sheet
Assets:
Current:
Commodity derivatives	$	—	$	108	$	—	$	108	$	(102)	$	6
Noncurrent:
Commodity derivatives	—		31		—		31		(20)		11

Liabilities:
Current:
Commodity derivatives	—		(214)		—		(214)		102		(112)
Noncurrent:
Commodity derivatives	—		(27)		—		(27)		20		(7)

Net derivative instruments	$	—	$	(102)	$	—	$	(102)	$	—	$	(102)

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2020

Unaudited

Concentrations of credit risk.At ~~September 30, 2017~~,March 31, 2020, 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 75 for additional information regarding the Company’s derivative activities and counterparties.

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

values.

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

Impairments of proved oil and natural gas properties are charged to accumulated depletion.

The Company calculates the expected undiscounted future net cash flows of its long-lived assets and their integrated assets using management’s assumptions and expectations of (i) commodity prices, which are based on the New York Mercantile Exchange (“NYMEX”) strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, and (vii) prevailing market rates of income and expenses from integrated assets.

At ~~September 30, 2017,~~ March 31, 2020, the Company’s estimates of commodity prices for purposes of determining undiscounted future cash flows, which ~~are~~were based on the NYMEX strip, ranged from a ~~2017~~2020 price of ~~$52.29~~$28.22 per barrel of oil ~~decreasing~~increasing to a ~~2021~~2026 price of ~~$50.77 per barrel of oil partially recovering to a 2024 price of $52.01~~$46.00 per barrel of oil. ~~Similarly, natural~~Natural gas prices ranged from a ~~2017~~2020 price of ~~$3.14~~$1.99 per Mcf of natural gas ~~decreasing~~increasing to a ~~2020~~2026 price of ~~$2.85~~$2.50 per ~~Mcf of~~Mcf. Both oil and natural gas ~~partially recovering to a 2024 price of $2.88 per Mcf of natural gas. Commodity~~commodity prices for this purpose were held flat after ~~2024.~~

2026.

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

At March 31, 2020, the Company's estimates of commodity prices ~~(ii) pricing adjustments~~ for ~~differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves~~purposes of determining discounted future cash flows ranged from a 2020 price of $28.22 per barrel of oil increasing to a 2026 price of $46.00 per barrel of oil. Natural gas prices ranged from a 2020 price of $1.99 per Mcf increasing to a 2026 price of $2.50 per Mcf of natural gas. These prices were then adjusted for location and ~~risk-adjusted probable~~quality differentials. Both oil and ~~possible reserves, (vii) prevailing market rates~~natural gas commodity prices for this purpose were held flat after 2026. Costs were adjusted for potential service cost deflation and then inflated in periods of ~~income and expenses from integrated assets and (viii) a discount rate.~~rising commodity prices. The expected future net cash flows were discounted using ~~an annual~~a rate of 10 percent, ~~to determine fair value. These are classified as Level 3 fair value assumptions.~~

which the Company believes is a market-based weighted average cost of capital for industry peers determined appropriate at the time of the valuation.

During the three months ended March 31, ~~2016,~~2020, NYMEX strip prices declined significantly as compared to December 31, ~~2015,~~2019, resulting in a significant decrease in value of the Company’s economically recoverable proved oil and ~~as a result~~natural gas reserves. As such, the carrying amount of the Company’s ~~Yeso field of approximately $3.4 billion~~proved oil and natural gas properties exceeded the expected undiscounted future net cash flows resulting in ~~a non-cash charge~~impairment charges against earnings of ~~approximately $1.5 billion. The non-cash charge represented the amount by which~~$7.8 billion, reducing the carrying ~~amount exceeded~~values of the Company’s Midland Basin and Delaware Basin to their estimated fair values of approximately $3.1 billion and $3.9 billion, respectively. These impairment charges are included in impairments of long-lived assets on the consolidated statement of operations for the three months ended March 31, 2020. The Company did 0t recognize an impairment of proved oil and natural gas properties during the three months ended March 31, 2019.

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects. During the three months ended March 31, 2020 and 2019, the Company recognized expenses of

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2020

Unaudited

$2.7 billion and $30 million, respectively, related to unproved oil and natural gas property impairments and abandoned and expiring acreage, which are included in exploration and abandonments expense on the accompanying consolidated statements of operations.

The recent significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks, related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic and other supply factors provided indications of possible impairment of the Company’s unproved oil and natural gas properties. The Company calculated the estimated fair value of its unproved oil and natural gas properties based on the ~~assets.~~

discounted future cash flow model and then corroborated these results to recent market data, when available. The ~~following table reports the carrying amount, estimated fair value and impairment expense of long-lived assets for the indicated period:~~

Estimated

Carrying

Fair Value

Impairment
(in millions)

Amount

(Level 3)

Expense

March 2016

$
3,438

$
1,913

$
1,525

It is reasonably possible that the estimate of undiscounted future net cash flows of the Company’s long-lived assets may change in the future resulting in the need to impair carrying values. The primary factors that may affectCompany's estimates of commodity prices for purposes of determining discounted future cash flows ~~are (i) commodity prices including differentials, (ii) increases or decreases~~were similar to the inputs used in ~~production and capital costs, (iii)~~

~~Concho Resources Inc.~~

~~Condensed Notes~~the proved property impairments discussed above. The discounted cash flows were further reduced by risk adjustments applied to ~~Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

~~future reserve volume adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted~~ probable and possible ~~reserves, (iv) results~~reserves. These are classified as Level 3 fair value assumptions. As a result, the Company recognized an impairment charge of approximately $2.7 billion to reduce the carrying value of certain unproved properties to their fair value as the Company’s future ~~drilling activities~~development plans became more uncertain due to significant declines in commodity prices. The expenses recognized during the three months ended March 31, 2019 were primarily due to certain abandoned and ~~(v) changes in income and expenses from integrated assets.~~

expiring acreage.

Note 7. 5. 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 ~~are thus recorded~~records these contracts at cost.

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

The following table summarizes the amounts reported in earnings related to the commodity derivative instruments for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2020 and ~~2016:~~

2019:


			Three Months Ended				Nine Months Ended
			September 30,				September 30,					Three Months Ended March 31,
(in millions)	(in millions)			2017		2016		2017		2016	(in millions)	2020		2019
Gain (loss) on derivatives:											Gain (loss) on derivatives:
Oil derivatives											Oil derivatives	$	1,825	$	(1,056)
Natural gas derivatives											Natural gas derivatives	(56)		(3)
Total											Total	$	1,769	$	(1,059)

*Gain (loss) on derivatives:*
	Oil derivatives		$	(205)	$	36	$	260	$	(173)
	Natural gas derivatives			(1)		5		29		(3)
		Total	$	(206)	$	41	$	289	$	(176)



The following table represents the Company’s net cash receipts from (payments on) derivatives for the three and nine months ended September 30, 2017 and 2016:



			Three Months Ended				Nine Months Ended
			September 30,				September 30,
(in millions)				2017		2016		2017		2016

*Net cash receipts from (payments on) derivatives:*
	Oil derivatives		$	28	$	154	$	129	$	566
	Natural gas derivatives			2		1		(3)		16
		Total	$	30	$	155	$	126	$	582

The following table represents the Company’s net cash receipts from (payments on) derivatives for the three months ended March 31, 2020 and 2019:


	Three Months Ended March 31,
(in millions)	2020		2019
Net cash receipts from (payments on) derivatives:
Oil derivatives	$	172	$	3
Natural gas derivatives	29		(3)
Total	$	201	$	—

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

~~September 30, 2017~~

March 31, 2020

Unaudited

Commodity derivative ~~contracts at September 30, 2017.~~contracts. The following table sets forth the Company’s outstanding derivative contracts at ~~September 30, 2017~~.March 31, 2020. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at ~~September 30, 2017~~March 31, 2020 are expected to settle by December 31, ~~2019.~~2022.



	2020
	Second Quarter		Third Quarter		Fourth Quarter		Total		2021		2022
Oil Price Swaps – WTI: (a)
Volume (MBbl)	12,495		11,080		10,045		33,620		29,562		—
Price per Bbl	$	56.90	$	56.88	$	57.00	$	56.92	$	47.82	$	—
Oil Price Swaps – Brent: (b)
Volume (MBbl)	2,031		1,768		1,503		5,302		—		—
Price per Bbl	$	60.33	$	60.29	$	60.14	$	60.26	$	—	$	—




Oil Basis Swaps: (c)
Volume (MBbl)	12,769		11,441		10,364		34,574		25,550		—
Price per Bbl	$	(0.36)	$	(0.53)	$	(0.67)	$	(0.51)	$	0.57	$	—
Natural Gas Price Swaps – Henry Hub: (d)
Volume (BBtu)	32,314		30,038		28,498		90,850		69,350		36,500
Price per MMBtu	$	2.46	$	2.47	$	2.47	$	2.47	$	2.44	$	2.38
Natural Gas Basis Swaps – Henry Hub/El Paso Permian: (e)
Volume (BBtu)	23,960		22,080		21,770		67,810		51,100		36,500
Price per MMBtu	$	(1.07)	$	(1.07)	$	(1.07)	$	(1.07)	$	(0.78)	$	(0.72)
Natural Gas Basis Swaps – Henry Hub/WAHA: (f)
Volume (BBtu)	7,280		7,360		7,360		22,000		18,250		7,300
Price per MMBtu	$	(1.10)	$	(1.10)	$	(1.10)	$	(1.10)	$	(0.92)	$	(0.85)


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

Table of Contents

First

Second

Third

Fourth

Quarter

Quarter

Quarter

Quarter

Total
Oil Price Swaps: (a)


2017:


Volume (Bbl)

9,370,080

9,370,080

Price per Bbl

$
51.33
$
51.33

2018:


Volume (Bbl)

8,180,629

7,546,170

7,064,318

6,676,007

29,467,124

Price per Bbl
$
51.54
$
51.45
$
51.36
$
51.26
$
51.41

2019:


Volume (Bbl)

5,314,000

5,090,000

4,897,000

4,721,000

20,022,000

Price per Bbl
$
52.54
$
52.52
$
52.54
$
52.55
$
52.54
Oil Basis Swaps: (b)

2017:


Volume (Bbl)

8,508,000

8,508,000

Price per Bbl

$
(0.74)
$
(0.74)

2018:

Volume (Bbl)

7,936,000

7,521,000

6,961,000

6,684,000

29,102,000

Price per Bbl
$
(1.02)
$
(1.01)
$
(1.01)
$
(1.01)
$
(1.01)

2019:


Volume (Bbl)

4,581,000

4,428,000

4,262,000

4,139,000

17,410,000

Price per Bbl
$
(1.17)
$
(1.17)
$
(1.18)
$
(1.18)
$
(1.17)
Natural Gas Price Swaps: (c)

2017:

Volume (MMBtu)

14,673,000

14,673,000

Price per MMBtu

$
3.10
$
3.10

2018:

Volume (MMBtu)

11,156,000

10,641,000

10,219,000

9,904,000

41,920,000

Price per MMBtu
$
3.06
$
3.05
$
3.05
$
3.04
$
3.05

2019:

Volume (MMBtu)

2,791,533

2,681,387

2,578,537

2,489,535

10,540,992

Price per MMBtu
$
2.86
$
2.85
$
2.85
$
2.85
$
2.85



(a) The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price.
(b) The basis differential price is between Midland – WTI and Cushing – WTI.
(c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2020

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. ~~In September 2017,~~

At March 31, 2020, the Company ~~elected to enter into an “Investment Grade Period” under the Credit Facility, as defined below, which~~ had ~~the effect~~a net derivative asset position of ~~releasing all collateral formerly securing the Credit Facility. Additionally,~~$1,466 million as a result of outstanding derivative contracts, which is reflected in the ~~Company’s Investment Grade Period election along~~accompanying consolidated balance sheet. The Company assessed this balance for concentration risk and noted balances of $296 million, $211 million, $173 million, $126 million, $110 million and $102 million with ~~amendments to certain ISDA Agreements with the Company’s derivative counterparties, the Company’s derivatives are no longer secured. See~~ JPMorgan Chase Bank N.A., Wells Fargo Bank, N.A., Citibank, N.A., PNC Bank, N.A., Canadian Imperial Bank of Commerce and ING Capital Markets LLC., respectively.

Note ~~8 for additional information regarding the Credit Facility.~~

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

~~Note 8.~~ 6. Debt

The Company’s debt consisted of the following at ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016:~~

2019:

September 30,

December 31,
(in millions)

2017

2016

Credit facility

$
368

$
-
5.5% unsecured senior notes due 2022


-


600
5.5% unsecured senior notes due 2023


-


1,550
4.375% unsecured senior notes due 2025


600


600
3.75% unsecured senior notes due 2027


1,000


-
4.875% unsecured senior notes due 2047


800


-
Unamortized original issue premium (discount), net


(6)


22
Senior notes issuance costs, net

(24)

(31)

Less: current portion


-


-

Total long-term debt

$
2,738

$
2,741


(in millions)	March 31, 2020		December 31, 2019
Credit facility due 2022	$	—	$	—
4.375% unsecured senior notes due 2025 (a)	600		600
3.75% unsecured senior notes due 2027	1,000		1,000
4.3% unsecured senior notes due 2028	1,000		1,000
4.875% unsecured senior notes due 2047	800		800
4.85% unsecured senior notes due 2048	600		600
Unamortized original issue discount	(9)		(9)
Senior notes issuance costs, net	(35)		(36)
Less: current portion	—		—
Total long-term debt	$	3,956	$	3,955

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

Credit ~~facility.~~Facility. The Company’s ~~credit facility, as amended and restated (the “Credit Facility”),~~Credit Facility has a maturity date of May 9, 2022. At ~~September 30, 2017,~~March 31, 2020, the Company’s commitments from its bank group were $2.0 ~~billion.~~

~~In April 2017,~~billion, all of which were unused. During the ~~Company amended~~three months ended March 31, 2020, the weighted average interest rate on the Credit Facility ~~to extend~~was 3.1 percent. At March 31, 2020, the maturity date, increase the borrowing base and decrease unused lender commitments. The amendment also lowered the corporate ratings floor sufficient to automatically terminate an Investment Grade Period under the Credit Facility from (i) “Ba1” to “Ba2” for Moody’s Investors Service, Inc. (“Moody’s”) and (ii) “BB+” to “BB” for S&P Global Ratings (“S&P”).

The Company recorded a loss on extinguishment of debt of approximately $1 million during the nine months ended September 30, 2017 for the proportional amount of unamortized deferred loan costs associated with banks that are no longer in the Credit Facility syndicate as a result of the April 2017 amendment.

In September 2017, the Company elected to enter into an Investment Grade Period under the Credit Facility, which had the effect of releasing all collateral formerly securing the Credit Facility. If the Investment Grade Period under the Credit Facility terminates (whether automatically due to a downgrade of the Company’s credit ratings below certain thresholds or by the Company’s election), the Credit Facility will once again be secured by a first lien on substantially all of the Company’s oil and natural gas properties and by a pledge of the equity interests in its subsidiaries. At September 30, 2017, certainmajority of the Company’s 100 percent owned subsidiaries ~~are~~were guarantors under the Credit Facility.

During an Investment Grade Period, advances on the Credit Facility bear interest, at the Company’s option, based on (i) an alternative base rate, which is equal to the highest of (a) the prime rate of JPMorgan Chase Bank (4.25 percent at September 30, 2017), (b) the federal funds effective rate plus 0.5 percent and (c) the London Interbank Offered Rate (“LIBOR”) plus 1.0 percent or (ii) LIBOR. The Credit Facility’s interest rates and commitment fees on the unused portion of the available commitment vary depending on the Company’s credit ratings from Moody’s and S&P. At the Company’s current credit ratings, LIBOR Rate Loans and Alternate Base Rate Loans bear interest margins of 150 basis points and 50 basis points per annum, respectively, and commitment fees on the unused portion of the available commitment are 25 basis points per annum.

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

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

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

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

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

·~~restrictions on the payment of cash dividends.~~

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

~~In September 2017,~~right of payments with one another. The customary release provisions were enumerated and discussed in our Annual Report on Form 10-K for the Company issued $1,800 million in aggregate principal amount of unsecured senior notes, consisting of $1,000 million in aggregate principal amount of 3.75% unsecured senior notes due 2027 (the “3.75% Notes”) and $800 million in aggregate principal amount of 4.875% unsecured senior notes due 2047 (the “4.875% Notes” and, together with the 3.75% Notes, the “Notes”). The 3.75% Notes were issued at a price equal to 99.636 percent of par, and the 4.875% Notes were issued at a price equal to 99.749 percent of par. The Company received net proceeds of approximately $1,777 million.

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

~~In connection with the Tender Offer, the Company redeemed the remaining outstanding 5.5% Notes not purchased~~year ended December 31, 2019. There have been no material changes in the Tender Offer at a price, including the make-whole premium as determined in accordance with the indentures, of 102.75 percent of the unpaid principal amount plus accrued and unpaid interest. Additionally in September 2017, the Company completed a satisfaction and discharge of the redeemed notes, where the Company prepaid interest to October 13, 2017. The Company used the net proceeds from the offering of the Notes, together with cash on hand and borrowings under its Credit Facility, to fund the Tender Offer and the satisfaction and discharge of its obligations under the indentures of the 5.5% Notes.

Company’s guarantor structure since December 31, 2019.

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

~~As a result of these transactions, the Company recorded a loss on extinguishment of debt for the three and nine months ended September 30, 2017 as follows~~:

(in millions)

Tender Offer

Extinguishment

Total

Tender premium

$
36

$
-

$
36
Make-whole premium


-


25


25
Prepaid interest


-


2


2
Unamortized original issue premium


(11)


(8)


(19)
Unamortized deferred loan costs


12


9


21

Total loss on extinguishment of debt

$
37

$
28

$
65

At ~~September 30, 2017~~,March 31, 2020, the Company was in compliance with the covenants under all of its debt instruments.

~~Principal maturities~~

Table of ~~long-term debt.~~Contents~~Principal maturities of long-term debt outstanding at September 30, 2017 were as follows:~~

(in millions)

Remaining 2017

$

-
2018

-
2019

-
2020

-
2021

-
2022

368
Thereafter

2,400

Total
$

2,768

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2020

Unaudited

Interest expense. The following amounts have been incurred and charged to interest expense for the three ~~and~~ ~~nine~~months ended ~~September 30, 2017~~March 31, 2020 and ~~2016:~~

2019:


		Three Months Ended				Nine Months Ended
		September 30,				September 30,
(in millions)	(in millions)		2017		2016		2017		2016	(in millions)	Three Months Ended March 31,

(in millions)										(in millions)			2020			2019
	Cash payments for interest	$	73	$	109	$	138	$	215		$	51		$	63
Non-cash interest	Non-cash interest		1		3		5		7	Non-cash interest	2			1
Net changes in accruals	Net changes in accruals		(35)		(59)		(25)		(60)	Net changes in accruals	(6)			(13)
Interest costs incurred										Interest costs incurred	47			51
Less: capitalized interest										Less: capitalized interest	(5)			(4)
Total interest expense										Total interest expense	$	42		$	47
	Total interest expense	$	39	$	53	$	118	$	162

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

Note 9. 7. Commitments and contingencies

Legal actions. The Company is a party to proceedings and claims incidental to its business. ~~While many~~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 ~~these~~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 ~~involve inherent uncertainty,~~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 ~~amount of the liability, if~~loss for any ~~ultimately incurred with respect~~other litigation matters and claims that are reasonably possible to ~~any such proceedings or claims~~occur will ~~not~~ have a material adverse effect on ~~the Company’s consolidated~~its financial position, ~~as a whole or on its liquidity, capital resources or future~~ results of ~~operations.~~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 ~~reserves~~estimated accruals as ~~appropriate to reflect its assessment of the then current status of the matters.~~

appropriate.

Severance tax, royalty and joint interest audits. The Company is subject to routine severance, royalty and joint interest audits from regulatory bodies and non-operators and makes accruals as necessary for estimated exposure when deemed probable and estimable. Additionally, the Company is subject to various possible contingencies that arise primarily from interpretations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, allowable costs under joint interest arrangements and other matters. At ~~December 31, 2016, the Company had $7 million accrued for estimated exposure that has since been satisfied.~~ Although the Company believes that it has estimated its exposure with respect to the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued.

Commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including ~~drilling commitments,~~ water commitment agreements, throughput volume delivery commitments, fixed and variable power commitments, ~~fixed asset commitments~~sand commitment agreements and ~~maintenance~~other commitments. The following table summarizes the Company’s commitments at ~~September 30, 2017~~:

March 31, 2020:


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

Remaining 2017		$	10
2018			40
2019			59
2020			32
Remaining 2020				Remaining 2020	$	36
2021	2021		31	2021	69
2022	2022		26	2022	41
2023				2023	38
2024				2024	38
2025				2025	38
Thereafter	Thereafter		88	Thereafter	76
Total (a)				Total (a)	$	336
	Total	$	286

(a) Volume delivery commitments included in the table do not include the oil marketing contract discussed in the table below.				(a) Volume delivery commitments included in the table do not include the oil marketing contract discussed in the table below.

Table of Contents

~~Operating leases.~~Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2020

Unaudited

At March 31, 2020, the Company’s delivery commitments covered the following gross volumes of oil and natural gas:


	Oil (MMBbl) (a)	Natural Gas (MMcf)
Remaining 2020	30	1,819
2021	51	2,569
2022	51	18,838
2023	51	18,838
2024	47	17,065
2025	33	16,425
Thereafter	81	16,425
Total	344	91,979


(a) Included in the table above is an oil marketing contract with a third-party purchaser that requires the Company to deliver 50000 barrels of oil per day.

Leases. The Company leases ~~vehicles,~~office space, office equipment, drilling rigs, field equipment and ~~office facilities under non-cancellable operating leases. Lease~~vehicles. Right-of-use assets and lease liabilities are initially recorded at the commencement date based on the present value of lease payments ~~associated~~over the lease term. Leased assets may be used in joint operations with ~~these~~other working interest owners. When the Company is the operator in a joint arrangement, the right-of-use assets and lease liabilities are determined on a gross basis. Certain leases contain variable costs above the minimum required payments and are not included in the right-of-use assets or lease liabilities. Options to extend or terminate a lease are included in the lease term when it is reasonably certain the Company will exercise that option. For operating leases, ~~were approximately $2 million for each~~lease cost is recognized on a straight-line basis over the term of the lease.

Leases with an initial term of 12 months or less are not recorded on the consolidated balance sheets. The Company’s short-term leases are primarily composed of drilling rigs and certain field equipment. During the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016 and approximately $7~~2019, the Company’s gross lease costs related to its short-term leases were $55 million and $6$84 million, ~~for~~respectively, of which $35 million and $67 million, respectively, were capitalized as part of oil and natural gas properties. A portion of the ~~nine~~gross lease costs was reimbursed to the Company by other working interest owners.

There have been no material changes to the Company’s right-of-use assets and lease liabilities since December 31, 2019.

Note 8. Income taxes

The Company records income taxes through the use of an estimated annual effective tax rate and specific events that are discretely recognized as they occur. For the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, the Company recorded an income tax benefit of $1.6 billion and $194 million, respectively.

~~Future minimum lease commitments under non-cancellable operating leases~~ During the three months ended March 31, 2020, the Company recognized impairments of proved and unproved oil and natural gas properties of approximately $7.8 billion and $2.7 billion, respectively, which will cause its deferred tax balance to change from a net deferred tax liability to a net deferred tax asset by December 31, 2020, resulting in the establishment of a valuation allowance against the net deferred tax assets at ~~September 30, 2017~~ ~~were~~March 31, 2020. The Company recognized the valuation allowance as ~~follows:~~

an ordinary item in its estimated annual effective tax rate.

(in millions)

Remaining 2017

$
2
2018

9
2019

7
2020

6
2021

4
2022

-
Thereafter

1

Total
$
29

~~Note 10.~~ ~~Income~~At the end of each interim period, the Company applies an estimated annualized effective tax rate to the current period income or loss before income taxes,

which can produce interim effective tax rate fluctuations. The effective income tax rates were ~~36.7~~14 percent and ~~37.3~~22 percent for the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016, respectively, and 36.6~~2019, respectively. The difference between the U.S federal statutory rate of 21 percent and ~~36.9 percent~~the Company’s effective tax rate for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 was primarily due to the impact of the nondeductible goodwill impairment reported discretely, the change in valuation allowance and ~~2016, respectively. Total~~the impact of permanent differences, partially offset by state income taxes. The difference between the U.S federal statutory rate of 21 percent and the Company’s effective tax ~~expense~~rate for the ~~nine~~three months ended ~~September 30, 2017~~ ~~differed from amounts computed by applying the United States federal statutory tax rates to pre-tax income~~March 31, 2019 was primarily due to state income taxes and the impact of permanent differences, ~~between book~~partially offset by research and ~~taxable income.~~ development credits, net of unrecognized tax benefits.

The Company ~~recorded a discrete income~~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 ~~approximately $6 million for~~ the ~~nine months ended~~ ~~September 30, 2017~~ ~~related~~position. There were no significant changes to ~~excess~~the Company’s cumulative unrecognized tax benefits ~~on stock-based awards, which are recorded in~~since December 31, 2019.

In March 2020, the ~~income tax provision pursuant to ASU No. 2016-09, which was adopted on January 1, 2017.~~ ~~Total income tax benefit for the three months ended~~ ~~September 30, 2017 and the~~ ~~three and nine months ended~~ ~~September 30, 2016~~ ~~differed from amounts computed by applying~~President of the United States ~~federal statutory~~signed the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”), to stabilize the economy during the coronavirus pandemic. The CARES Act temporarily suspends and modifies

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2020

Unaudited

certain tax ~~rates to pre-tax loss primarily due to state income taxes, partially offset~~laws established by the 2017 tax reform law known as the Tax Cuts and Jobs Act, including, but not limited to, modifications to net operating loss limitations, business interest limitations and alternative minimum tax. The CARES Act did not have a material impact ~~of permanent differences between book~~on the Company’s current year provision and ~~taxable loss.~~

the Company’s consolidated financial statements.

Note ~~11.~~ 9.Related party transactions

The Company paid royalties on certain properties to a partnership in which a director of the Company is the general partner and owns a 3.5 percent limited partnership interest. These payments ~~were reported in the Company’s consolidated statements of operations and~~ totaled ~~approximately~~ $1 million and $2 million for ~~each of~~ the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016~~2019, respectively.

At March 31, 2020, the Company had ownership interests in entities that operate and ~~approximately $5~~manage various infrastructure assets and accounts for these investments using the equity method. The Company made payments to these entities of $29 million and $3$4 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, respectively.

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

Note ~~12.~~ 10.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, 2017~~March 31, 2020 and ~~2016, respectively,~~2019 under the two-class method:


				Three Months Ended				Nine Months Ended
			September 30,				September 30,					Three Months Ended March 31,
(in millions)	(in millions)		2017		2016		2017		2016		(in millions)	2020		2019
Net loss as reported											Net loss as reported	$	(9,277)	$	(695)
Participating basic earnings (a)											Participating basic earnings (a)	—		—
Basic loss attributable to common stockholders											Basic loss attributable to common stockholders	(9,277)		(695)
Reallocation of participating earnings											Reallocation of participating earnings	—		—
Diluted loss attributable to common stockholders											Diluted loss attributable to common stockholders	$	(9,277)	$	(695)

Net income (loss) as reported			$	(113)	$	(51)	$	689	$	(1,337)
Participating basic earnings (a)				-		-		(5)		-
	Basic earnings attributable to common stockholders			(113)		(51)		684		(1,337)
Reallocation of participating earnings				-		-		-		-
	Diluted earnings attributable to common stockholders		$	(113)	$	(51)	$	684	$	(1,337)


(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) 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.											(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.

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~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, 2017~~March 31, 2020 and ~~2016:~~2019:


	Three Months Ended March 31,
(in thousands)	2020	2019
Weighted average common shares outstanding:
Basic	195,326	199,148
Dilutive performance units	—	—
Diluted	195,326	199,148

Table of Contents

Three Months Ended

Nine Months Ended

September 30,

September 30,
(in thousands)

2017

2016

2017

2016

Weighted average common shares outstanding:




Basic

147,557

135,454

147,233

131,417

Dilutive common stock options

-

-

4

-

Dilutive performance units

-

-

549

-

Diluted

147,557

135,454

147,786

131,417

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2020

Unaudited

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

September 30,

Three Months Ended
March 31,

(in thousands)

2017

2016

2017

2016

(in thousands)

2020

2019

Number of antidilutive units:

Performance units

495

324

Number of antidilutive units:

Antidilutive performance units

107

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~~stockholder return relative to the total ~~shareholder~~stockholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total ~~shareholder~~stockholder 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~~0 and 300 percent.

See Note 3 for additional information on performance unit awards.

Note 11. Stockholders' equity

~~Concho Resources Inc.~~

~~Condensed Notes~~Share repurchase program. In September 2019, the Company announced that its board of directors authorized the initiation of a share repurchase program for up to ~~Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

~~Note 13.~~ ~~Subsidiary guarantors~~

At ~~September 30, 2017, certain~~$1.5 billion of the Company’s ~~100 percent owned subsidiaries have fully~~common stock. During January 2020, the Company repurchased and ~~unconditionally guaranteed~~retired 1,125,906 shares under the program at an aggregate cost of $100 million. As of March 31, 2020, the Company had repurchased and retired a total of 4,426,276 shares since the inception of the program at an aggregate cost of $350 million. The Company’s share repurchase program may be modified, suspended or terminated at any time by the Company’s ~~senior notes.~~board of directors. The Company is not obligated to acquire any specific number of shares.

Common stock dividends. The Company paid dividends of $39 million, or $0.20 per share, during the three months ended March 31, 2020. Any payment of future dividends will be at the discretion of the Company’s board of directors. Covenants contained in the Company’s agreement governing its Credit Facility and the indentures governing the Company’s senior notes ~~provide that~~could limit the ~~guarantees~~payment 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,~~dividends.

Table of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Company to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee.

See Note 8 for a summary of the Company’s senior notes. In accordance with practices accepted by the United States Securities and Exchange Commission, the Company has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. In addition, two of the Company’s subsidiaries do not guarantee the Company’s senior notes and are included in the Company’s consolidated financial statements. One of such entities is a VIE that was formed to effectuate a tax-free exchange of assets, and the other entity is a 100 percent owned subsidiary that was recently acquired. These entities are referred to as “Subsidiary Non-Guarantors” in the tables below.

Contents ~~The following condensed consolidating balance sheets at~~ ~~September 30, 2017 and December 31, 2016, condensed consolidating statements of operations for the three and~~ ~~nine~~ ~~months ended~~ ~~September 30, 2017 and 2016~~ ~~and condensed consolidating statements of cash flows for the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2017 and 2016,~~ ~~present financial information for~~

Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company.

~~Concho Resources Inc.~~

Condensed Notes to Consolidated Financial Statements

~~September 30, 2017~~

~~Unaudited~~

Condensed Consolidating Balance Sheet
September 30, 2017

Parent

Subsidiary

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors
Non-Guarantors

Entries


Total

ASSETS








Accounts receivable - related parties

$
8,903

$
(653)

$
-

$
(8,250)

$
-
Other current assets


14

515

6

-

535
Oil and natural gas properties, net


-

11,968

619

-

12,587
Property and equipment, net


-

232

-

-

232
Investment in subsidiaries


2,963

-

-

(2,963)

-
Other long-term assets


42

86

-

-

128

Total assets

$
11,922

$
12,148

$
625

$
(11,213)

$
13,482









LIABILITIES AND EQUITY







Accounts payable - related parties

$
(653)

$
8,290

$
613

$
(8,250)

$
-
Other current liabilities


50

756

4

-

810
Long-term debt


2,738

-

-

-

2,738
Other long-term liabilities


1,156

141

6

-

1,303
Equity


8,631

2,961

2

(2,963)

8,631

Total liabilities and equity

$
11,922

$
12,148

$
625

$
(11,213)

$
13,482

Condensed Consolidating Balance Sheet
December 31, 2016

Parent

Subsidiary

Consolidating

(in millions)


Issuer


Guarantors

Entries


Total

ASSETS






Accounts receivable - related parties

$
8,991

$
(336)

$
(8,655)

$
-
Other current assets


12

534

-

546
Oil and natural gas properties, net


-

11,086

-

11,086
Property and equipment, net


-

216

-

216
Investment in subsidiaries


1,989

-

(1,989)

-
Other long-term assets


11

260

-

271

Total assets

$
11,003

$
11,760

$
(10,644)

$
12,119







LIABILITIES AND EQUITY





Accounts payable - related parties

$
(336)

$
8,991

$
(8,655)

$
-
Other current liabilities


114

639

-

753
Long-term debt


2,741

-

-

2,741
Other long-term liabilities


861

141

-

1,002
Equity


7,623

1,989

(1,989)

7,623

Total liabilities and equity

$
11,003

$
11,760

$
(10,644)

$
12,119

March 31, 2020

Unaudited

~~Concho Resources Inc.~~

~~Condensed Notes to Consolidated Financial Statements~~

~~September 30, 2017~~

~~Unaudited~~

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
Three Months Ended September 30, 2016

Parent

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors

Entries


Total



Total operating revenues

$
-

$
430

$
-

$
430
Total operating costs and expenses


41

(469)

-

(428)

Income (loss) from operations


41

(39)

-

2
Interest expense


(52)

(1)

-

(53)
Loss on extinguishment of debt


(28)

-

-

(28)
Other, net


(42)

(2)

42

(2)

Loss before income taxes


(81)

(42)

42

(81)
Income tax benefit


30

-

-

30

Net loss

$
(51)

$
(42)

$
42

$
(51)

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

(835)

(6)

-

(553)

Income from operations


288

963

2

-

1,253
Interest expense


(117)

(1)

-

-

(118)
Loss on extinguishment of debt


(66)

-

-

-

(66)
Other, net


982

18

-

(982)

18

Income before income taxes


1,087

980

2

(982)

1,087
Income tax expense


(398)

-

-

-

(398)

Net income

$
689

$
980

$
2

$
(982)

$
689

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2016

Parent

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors

Entries


Total



Total operating revenues

$
-

$
1,110

$
-

$
1,110
Total operating costs and expenses


(177)

(2,853)

-

(3,030)

Loss from operations


(177)

(1,743)

-

(1,920)
Interest expense


(159)

(3)

-

(162)
Loss on extinguishment of debt


(28)

-

-

(28)
Other, net


(1,755)

(10)

1,756

(9)

Loss before income taxes


(2,119)

(1,756)

1,756

(2,119)
Income tax benefit


782

-

-

782

Net loss

$
(1,337)

$
(1,756)

$
1,756

$
(1,337)

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

$
-

$
-

$
-

$
-

$
-

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2016

Parent

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors

Entries


Total



Net cash flows provided by (used in) operating activities

$
(694)

$
1,713

$
-

$
1,019
Net cash flows used in investing activities


-

(783)

-


(783)
Net cash flows provided by financing activities


694

-

-


694

Net increase in cash and cash equivalents


-

930

-

930

Cash and cash equivalents at beginning of period


-

229

-

229

Cash and cash equivalents at end of period

$
-

$
1,159

$
-

$
1,159

Note ~~14.~~ 12.Subsequent events

2020 dividends.On April 28, 2020, the Company’s board of directors approved a cash dividend of $0.20 per share for the second quarter of 2020 that is expected to be paid on June 26, 2020 to stockholders of record as of May 8, 2020.

New commodity derivative contracts.After ~~September 30, 2017,~~March 31, 2020, the Company entered into the following ~~oil price swaps, oil basis swaps and natural gas price swaps~~derivative contracts to hedge additional amounts of ~~the Company’s~~ estimated future production:

First

Second

Third

Fourth

Quarter

Quarter

Quarter

Quarter

Total

Oil Price Swaps: (a)

2017:

Volume (Bbl)

846,000

846,000

Price per Bbl

$
51.29
$
51.29

2018:

Volume (Bbl)

953,000

600,000

407,000

296,000

2,256,000

Price per Bbl
$
51.55
$
51.39
$
51.43
$
51.28
$
51.45

2019:

Volume (Bbl)

1,035,000

1,046,500

828,000

828,000

3,737,500

Price per Bbl
$
51.25
$
51.25
$
51.14
$
51.14
$
51.20
Oil Basis Swaps: (b)

2017:

Volume (Bbl)

1,499,000

1,499,000

Price per Bbl

$
(0.12)
$
(0.12)

2018:

Volume (Bbl)

540,000

546,000

276,000

276,000

1,638,000

Price per Bbl
$
(0.21)
$
(0.21)
$
(0.38)
$
(0.38)
$
(0.27)

2019:

Volume (Bbl)

1,395,000

1,410,500

1,426,000

1,426,000

5,657,500

Price per Bbl
$
(0.68)
$
(0.68)
$
(0.68)
$
(0.68)
$
(0.68)
Natural Gas Price Swaps: (c)

2017:

Volume (MMBtu)

3,660,000

3,660,000

Price per MMBtu

$
3.02
$
3.02

2018:

Volume (MMBtu)

5,400,000

5,460,000

4,600,000

4,600,000

20,060,000

Price per MMBtu
$
3.02
$
3.02
$
3.01
$
3.01
$
3.02

2019:

Volume (MMBtu)

1,800,000

1,820,000

1,840,000

1,840,000

7,300,000

Price per MMBtu
$
2.86
$
2.86
$
2.86
$
2.86
$
2.86

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


	2020
	Second Quarter		Third Quarter		Fourth Quarter		Total		2021		2022
Oil Price Swaps – WTI: (a)
Volume (MBbl)	2,064		1,554		736		4,354		1,095		730
Price per Bbl	$	31.34	$	34.26	$	35.46	$	33.08	$	36.76	$	38.68
Oil Price Swaps – Brent: (b)
Volume (MBbl)	—		647		974		1,621		—		—
Price per Bbl	$	—	$	30.60	$	32.08	$	31.49	$	—	$	—
Oil Basis Swaps: (c)
Volume (MBbl)	1,729		1,247		828		3,804		5,107		—
Price per Bbl	$	(2.64)	$	(1.21)	$	(1.02)	$	(1.82)	$	0.15	$	—
Natural Gas Price Swaps – Henry Hub: (d)
Volume (BBtu)	—		1,830		2,760		4,590		17,330		—
Price per MMBtu	$	—	$	2.49	$	2.49	$	2.49	$	2.66	$	—
Natural Gas Basis Swaps – Henry Hub/El Paso Permian: (e)
Volume (BBtu)	—		1,220		1,840		3,060		10,950		—
Price per MMBtu	$	—	$	(0.44)	$	(0.44)	$	(0.44)	$	(0.63)	$	—
Natural Gas Basis Swaps – Henry Hub/WAHA: (f)
Volume (BBtu)	—		610		920		1,530		—		—
Price per MMBtu	$	—	$	(0.45)	$	(0.45)	$	(0.45)	$	—	$	—


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

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2020

Unaudited

Note ~~15.~~ 13.Supplementary information

Capitalized costs


			September 30,		December 31,
(in millions)	(in millions)		2017		2016		(in millions)	March 31, 2020		December 31, 2019
Oil and natural gas properties:							Oil and natural gas properties:
Proved							Proved	$	23,500	$	22,915
Unproved							Unproved	3,144		5,870
Less: accumulated depletion							Less: accumulated depletion	(16,182)		(7,895)
Net capitalized costs for oil and natural gas properties							Net capitalized costs for oil and natural gas properties	$	10,462	$	20,890

*Oil and natural gas properties:*
	Proved		$	17,950	$	16,620
	Unproved			2,804		1,856
	Less: accumulated depletion			(8,167)		(7,390)
		Net capitalized costs for oil and natural gas properties	$	12,587	$	11,086

Costs incurred for oil and natural gas producing activities



		Three Months Ended				Nine Months Ended
		September 30,				September 30,					Three Months Ended March 31,
(in millions)	(in millions)	2017		2016		2017		2016		(in millions)	2020		2019

Property acquisition costs:	Property acquisition costs:									Property acquisition costs:
	Proved	$	162	$	1	$	301	$	257
	Unproved		472		14		865		172
Proved										Proved	$	7	$	—
Unproved										Unproved	5		4
Exploration	Exploration		252		177		725		513	Exploration	297		462
Development	Development		175		97		478		287	Development	270		464
Total costs incurred for oil and natural gas properties										Total costs incurred for oil and natural gas properties	$	579	$	930
	Total costs incurred for oil and natural gas properties	$	1,061	$	289	$	2,369	$	1,229

Table of Contents

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

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

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

Overview

~~We are~~

Concho Resources Inc. (“Concho,” the “Company,” “we,” “us,” and “our”) is an independent ~~oil and natural gas company engaged in the acquisition, development,~~ exploration and production company. We are one of ~~oil and natural gas properties. Our core operations are primarily focused~~the largest operators in the Permian Basin of ~~southeast~~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 ~~applying new technologies, such as extended length lateral drilling, multi-well pad~~developing our resource base by utilizing large-scale development ~~and~~projects, which include long-lateral wells, enhanced completion techniques and multi-well pad locations, throughout our ~~four core~~ operating ~~areas: the Northern Delaware Basin, the Southern Delaware Basin, the Midland Basin and the New Mexico Shelf. Oil comprised~~ ~~59 percent of our 720 MMBoe of estimated proved reserves at December 31, 2016 and 62 percent of our 186,449 Boe of average daily production for the nine months ended~~ ~~September 30, 2017~~. ~~We seek to operate the wells in which we own an interest, and we operated wells that accounted for 92 percent of our proved developed producing reserves and 79 percent of our 7,858 gross wells at~~ ~~December 31, 2016. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and stimulation methods used.~~

areas.

Financial and Operating Performance

Our financial and operating performance for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016~~2019 included the following highlights:

•Net ~~income~~loss was $~~689 million~~$9,277 million ($~~4.63~~(47.49) per diluted share) as compared to net loss of ~~$1.3billion~~$695 million ($~~(10.18)~~(3.49) per diluted share) for the ~~first nine~~three months ~~of 2017~~ended March 31, 2020 and ~~2016,~~2019, respectively. The increase in net loss was primarily due to:

•~~no recorded~~$7,772 million of impairments of ~~long-lived assets during the nine months ended September 30, 2017, as compared to $1.5 billion in non-cash impairment charges in 2016~~, ~~primarily attributable to properties in~~ our ~~New Mexico Shelf area;~~

•~~$696 million increase in~~proved oil and natural gas ~~revenues as a result of~~ a 28~~percent~~properties during the three months ended March 31, 2020;

•$2,672 million increase in ~~production~~exploration and ~~a 28 percent increase in commodity price realizations per Boe~~ ~~(excluding the effects of derivative activities);~~

•~~gain on disposition of assets, net increased $558 million due to a gain of approximately $667~~ ~~million during the nine months ended September 30, 2017~~abandonments primarily due to impairments of our ~~disposition~~unproved oil and natural gas properties during the three months ended March 31, 2020;

•$1,917 million of ~~Alpha Crude Connector, LLC (“ACC”), as compared~~impairments of goodwill during the three months ended March 31, 2020; and

•$199 million change in other income primarily due to ~~a gain~~an impairment to one of ~~approximately $109 million~~our equity method investments during ~~2016 primarily attributable to our Northern Delaware Basin divestiture in February 2016;~~

the three months ended March 31, 2020.

partially offset by:

•$~~465~~ 2,828 million change in (gain) loss on derivatives due to a ~~$289 million~~ gain on derivatives of $1,769 million during the ~~nine~~three months ended ~~September 30, 2017, as compared to a~~ ~~$176 million loss on derivatives~~ ~~during 2016;~~ ~~and~~

•~~$42 million decrease in depreciation, depletion and amortization expense, primarily due to a decrease in the depletion rate per Boe period over period, partially offset by an increase in production;~~

~~partially offset by:~~

•~~$1.2 billion change in our income tax provision due to income before income taxes during the nine months ended September 30, 2017,~~March 31, 2020 as compared to a loss ~~before income taxes during 2016;~~

on derivatives of $1,059 million in 2019; and

•$531,373 million increase in ~~production expense, primarily~~income tax benefits due to ~~increased production associated with our wells successfully drilled and completed~~a $1,567 million tax benefit during the three months ended March 31, 2020, as compared to $194 million in ~~2016 and 2017; and~~

2019.

•~~$51 million increase in production and ad valorem tax expense, primarily due to increased production taxes as a result of increased oil and natural gas sales.~~

·Average daily sales volumes of ~~186,449~~ ~~Boe~~326 MBoe per day during the ~~first nine~~three months ~~of 2017 increased 28 percent~~ended March 31, 2020 as compared to ~~145,868 Boe~~328 MBoe per day during ~~2016.~~

·the same period in 2019.

•Net cash provided by operating activities increased by ~~approximately $166~~$213 million to ~~$1,185~~$836 million for the ~~first nine~~three months ~~of 2017,~~ended March 31, 2020, as compared to ~~$1,019~~ m~~illion in~~$623 million for the ~~first nine~~three months ~~of 2016,~~ended March 31, 2019, primarily due to an increase in net cash settlements received from derivatives, partially offset by the decrease in oil and natural gas revenues and decreased cash interest expense, partially offset by (i) a decrease in cash settlements on derivatives, (ii) increased production expense, (iii) increased production tax expense and (iv) changes related to cash income taxes.

·~~Cash decreased by approximately $53 million during the first nine months~~revenues.

Table of 2017 primarily as a result of cash paid to tender and extinguish our 5.5% Notes, as defined below, and cash paid for the Midland Basin and Northern Delaware Basin acquisitions, partially offset by proceeds from the issuance of the Notes, as defined below, and proceeds from our February 2017 divestiture of ACC.

Contents

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. Recently, there has been a substantial decrease in oil and natural gas prices due in part to significantly decreased demand as a result of the novel coronavirus (“COVID-19”) pandemic and an oversupply of crude oil driven by a dispute between members of the Organization of Petroleum Exporting Countries (“OPEC”) and Russia over production cuts, each of which are discussed below under “Other events”. A combination of these factors resulted in the price of oil to fall below zero to $(37.63) per barrel of oil on April 20, 2020 recovering the following day to $10.01 per barrel of oil. Factors that may impact future commodity prices, including the price of oil ~~natural gas~~ and natural gas, ~~liquids,~~ include but are not limited to:

·~~continuing economic uncertainty worldwide;~~

·~~political~~

•the overall global demand for oil and ~~economic developments in~~natural gas;

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

•the overall North American oil and natural gas ~~producing regions, including Africa, South America~~supply and demand fundamentals, including:

•the ~~Middle East;~~

·~~the extent~~U.S. economy,

•weather conditions, and

•liquefied natural gas (“LNG”) deliveries 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;~~

·~~domestic and foreign governmental regulations, including limits on~~exports from the United ~~States’ ability~~States;

•economic conditions worldwide, including adverse conditions driven by political, weather or health events, including, but not limited to, ~~export crude oil, and taxation;~~

·the ~~level of global inventories;~~

·COVID-19 pandemic;

•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;

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

•the ~~quality~~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 ~~we produce;~~

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

·producing regions, including Africa, South America and the ~~domestic~~Middle East;

•the extent to which members of OPEC and ~~foreign~~other oil exporting nations are able to influence global oil supply levels;

•changes in trade relations and policies, including the imposition of tariffs by the United States or China;

•technological advances or social attitudes and policies affecting energy consumption and energy supply;

•activism or activities by non-governmental organizations to limit certain sources of capital for the energy sector or restrict the exploration, development and production of oil and gas;

•the effect of energy conservation efforts, alternative fuel requirements and climate change-related initiatives;

•additional restrictions on the exploration, development and production of oil, natural gas and natural gas ~~liquids;~~

·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 ~~United States~~U.S. dollar, on which oil prices are benchmarked globally, against foreign currencies;

•domestic and foreign governmental regulations, including limits on the ~~effect of energy conservation efforts;~~

·United States’ ability to export crude oil, and taxation;

•the ~~price~~cost and availability of ~~alternative fuels;~~products and

·~~overall North American~~ personnel needed for us to produce oil ~~natural gas~~ and natural gas, ~~liquids supply~~including rigs, crews, sand, water and ~~demand fundamentals, including:~~

water disposal;

•the ~~United States economy,~~

quality of the oil we produce; and

•~~weather conditions, and~~

•~~liquefied natural gas deliveries to~~the price, availability and ~~exports from the United States.~~

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 ~~expect that we~~ may ~~economically~~ hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Notes 75 and 1412 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, 2017~~March 31, 2020 and additional derivative contracts entered into subsequent to ~~September 30, 2017,~~March 31, 2020, respectively.

~~Oil and natural gas prices have been subject to significant fluctuations during the past several years. The average oil and natural gas prices were higher during the comparable periods~~

Table of ~~2017 measured against 2016.~~ Contents

The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, as well as the high and low NYMEX prices for the same periods:


			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2017		2016		2017		2016			Three Months Ended March 31,
												2020		2019
Average NYMEX prices:	Average NYMEX prices:										Average NYMEX prices:
	Oil (Bbl)		$	48.12	$	45.03	$	49.45	$	41.45
	Natural gas (MMBtu)		$	2.95	$	2.80	$	3.06	$	2.35
Oil (Bbl)											Oil (Bbl)	$	46.35	$	54.87
Natural gas (MMBtu)											Natural gas (MMBtu)	$	1.87	$	2.88

High and Low NYMEX prices:	High and Low NYMEX prices:										High and Low NYMEX prices:
Oil (Bbl):											Oil (Bbl):
High											High	$	63.27	$	60.14
Low											Low	$	20.09	$	45.41
Natural gas (MMBtu):											Natural gas (MMBtu):
High											High	$	2.20	$	3.59
Low											Low	$	1.60	$	2.55
	*Oil (Bbl):*
		High	$	52.22	$	48.99	$	54.45	$	51.23
		Low	$	44.23	$	39.51	$	42.53	$	26.21
	*Natural gas (MMBtu):*
		High	$	3.15	$	3.06	$	3.72	$	3.06
		Low	$	2.77	$	2.55	$	2.56	$	1.64

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of ~~$54.15~~$28.34 and ~~$49.29~~$(37.63) per Bbl and ~~$3.01~~$1.94 and ~~$2.75~~$1.55 per MMBtu, respectively, during the period from~~October~~April 1, ~~2017~~2020to ~~October 30, 2017.~~April 27, 2020. At ~~October 30, 2017,~~April 27, 2020, the NYMEX oil price and NYMEX natural gas price were ~~$54.15~~$12.78 per Bbl and ~~$2.97~~$1.82 per MMBtu, respectively.

~~Historically, and during the nine months ended September 30, 2017, 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. The average Mont Belvieu price for a blended barrel of natural gas liquids was ~~$25.04~~$15.09 per Bbl and ~~$17.82~~$24.13 per Bbl during the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016, respectively,~~2019, respectively.

Recent Events and ~~$23.74~~Outlook

2020 dividends. On April 28, 2020, our board of directors approved a cash dividend of $0.20 per ~~Bbl and $16.82 per Bbl~~share for the second quarter of 2020 that is expected to be paid on June 26, 2020 to stockholders of record as of May 8, 2020. Total cash dividends paid to our stockholders during the ~~nine~~three months ended ~~September 30, 2017 and 2016, respectively.~~

March 31, 2020 were $39 million.

~~Recent Events~~

~~Senior notes.~~2020 capital budget. In ~~September 2017, we issued $1,800 million~~March 2020, in aggregate principal amount of unsecured senior notes, consisting of $1,000 million in aggregate principal amount of 3.75% unsecured senior notes due 2027 (the “3.75% Notes”) and $800 million in aggregate principal amount of 4.875% unsecured senior notes due 2047 (the “4.875% Notes” and, together with the 3.75% Notes, the “Notes”). We used the net proceeds of approximately $1,777 million, together with cash on hand and borrowings under the Credit Facility, as defined below, to fund the cash tender offer (the “Tender Offer”) and the satisfaction and discharge of the outstanding $600 million aggregate principal amount of our 5.5% unsecured senior notes due 2022 and the outstanding $1,550 million aggregate principal amount of our 5.5% unsecured senior notes due 2023 (collectively, the “5.5% Notes”). As a result of these transactions, we recorded a loss on extinguishment of debt relatedresponse to the ~~5.5% Notes of approximately $65 million during each of the three and nine months ended September 30, 2017.~~ ~~See Note 8 of the Condensed Notes to Consolidated Financial Statements included~~substantial decrease in ~~“Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our senior notes.~~

~~Investment grade period~~. In September 2017, we elected to enter into an “Investment Grade Period” under the amended and restated credit facility (the “Credit Facility”), which had the effect of releasing all collateral formerly securing the Credit Facility. If the Investment Grade Period under the Credit Facility terminates (whether automatically due to a downgrade of our credit ratings below certain thresholds or by our election), the Credit Facility will once again be secured by a first lien on substantially all of our oil and natural gas prices, we announced that we reduced our 2020 planned capital expenditures to approximately $1.6 billion from the $2.6 billion to $2.8 billion range previously announced. Based on our current expectations of commodity prices and cost, we expect to fund our 2020 capital budget primarily with operating cash flows. However, if we experience sustained commodity prices lower than our forecasted pricing without sufficient costs reductions, we may adjust our capital budget to preserve our financial strength.

Share repurchase program. In September 2019, we announced that our board of directors authorized the initiation of a share repurchase program for up to $1.5 billion of our common stock. During January 2020, we repurchased and retired 1,125,906 shares under the program at an aggregate cost of $100 million. As of March 31, 2020, the Company had repurchased and retired a total of 4,426,276 shares since the inception of the program at an aggregate cost of $350 million.

Other events. In December 2019, COVID-19 was reported to have surfaced in China. The global spread of this virus has caused business disruption around the world beginning in January 2020, including disruption to the oil and natural gas industry. In March 2020, the World Health Organization declared the outbreak of COVID-19 to be a pandemic, and the U.S. economy began to experience pronounced effects. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains and created significant volatility and disruption of financial and commodity markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. As a result, there has been a significant reduction in demand for and prices of oil and natural gas. The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including how the pandemic and measures taken in response to it impact demand for oil and natural gas, the availability of personnel, equipment and services critical to our ability to operate our properties and the impact of potential governmental restrictions on travel, transports and operations. There is uncertainty around the extent and duration of the disruption, including any potential resurgence. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the U.S. and world economies and market conditions, and how quickly and to what extent normal economic and operating conditions can resume.

Table of Contents

Additionally, the industry is experiencing an oversupply of crude oil driven by a ~~pledge~~dispute between OPEC and Russia over production cuts and a resulting decision by Saudi Arabia and other Persian Gulf members of OPEC to increase production. In April 2020, OPEC and Russia agreed to certain production cuts. If these cuts are effected, however, they may not offset near-term demand loss attributable to the ~~equity interests~~COVID-19 pandemic and the related economic slowdown, and so far, the tentative agreement has not resulted in increased commodity prices. In response to an oversupply of crude oil and corresponding low prices, there has been a significant decline in drilling by U.S. producers starting in mid-March 2020, but domestic supply has continued to exceed demand, which has led to significant operational stress with respect to capacity limitations associated with storage, pipeline and refining infrastructure, particularly in the Gulf Coast region. As storage capacity becomes fully subscribed, possibly by the end of May 2020, we may be forced to curtail some portion or all of our ~~subsidiaries. Additionally,~~estimated production. In response to these matters, the Company has reduced its planned capital expenditures for 2020, as discussed below, and, as a result, ofexpects production to decrease in 2020. Therefore, while we expect these matters to negatively impact our ~~Investment Grade Period election along with amendments to certain International Swap Dealers Association Master Agreements (“ISDA Agreements”) with~~short-term results, including our ~~derivative counterparties, our derivatives are no longer secured.~~

~~Midland Basin acquisition.~~~~In July 2017, we completed an acquisition in~~revenues and operating costs, as well as operating cash flows, the ~~Midland Basin. As consideration for the acquisition, we paid approximately $595 million in cash. The acquisition is subject to customary post-closing adjustments.~~ ~~Concurrent with the acquisition, we entered into a transaction structured as a reverse like-kind exchange in accordance with Section 1031~~degree of the Internal Revenue Code of 1986. See Note 4 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regardingadverse impact cannot be reasonably estimated at this ~~transaction.~~

time.

Derivative Financial Instruments

Derivative financial instrument exposure.At ~~September 30, 2017~~,March 31, 2020, the fair value of our financial derivatives was a net ~~liability~~ asset of $11~~million.~~$1.5 billion. Under the terms of our financial derivative instruments, we do not have exposure to potential “margin calls” on our financial derivative instruments. We currently have no reason to believe that our counterparties to these commodity derivative contracts are not financially viable. The terms of our credit facility, as amended and restated (“Credit ~~Facility~~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. ~~In September 2017,~~

New commodity derivative contracts.After March 31, 2020, we ~~elected~~entered into derivative contracts to ~~enter into an Investment Grade Period under the Credit Facility, which had the effect~~hedge additional amounts of ~~releasing all collateral formerly securing the Credit Facility and derivative obligations. See~~estimated future production. Refer to Note 812 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding ~~our Credit Facility.~~

~~New~~these commodity derivative contracts.~~After September 30, 2017, we entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts~~

Table of ~~our estimated future production:~~

First

Second

Third

Fourth

Quarter

Quarter

Quarter

Quarter

Total

Oil Price Swaps: (a)

2017:

Volume (Bbl)

846,000

846,000

Price per Bbl

$
51.29
$
51.29

2018:

Volume (Bbl)

953,000

600,000

407,000

296,000

2,256,000

Price per Bbl
$
51.55
$
51.39
$
51.43
$
51.28
$
51.45

2019:

Volume (Bbl)

1,035,000

1,046,500

828,000

828,000

3,737,500

Price per Bbl
$
51.25
$
51.25
$
51.14
$
51.14
$
51.20
Oil Basis Swaps: (b)

2017:

Volume (Bbl)

1,499,000

1,499,000

Price per Bbl

$
(0.12)
$
(0.12)

2018:

Volume (Bbl)

540,000

546,000

276,000

276,000

1,638,000

Price per Bbl
$
(0.21)
$
(0.21)
$
(0.38)
$
(0.38)
$
(0.27)

2019:

Volume (Bbl)

1,395,000

1,410,500

1,426,000

1,426,000

5,657,500

Price per Bbl
$
(0.68)
$
(0.68)
$
(0.68)
$
(0.68)
$
(0.68)
Natural Gas Price Swaps: (c)

2017:

Volume (MMBtu)

3,660,000

3,660,000

Price per MMBtu

$
3.02
$
3.02

2018:

Volume (MMBtu)

5,400,000

5,460,000

4,600,000

4,600,000

20,060,000

Price per MMBtu
$
3.02
$
3.02
$
3.01
$
3.01
$
3.02

2019:

Volume (MMBtu)

1,800,000

1,820,000

1,840,000

1,840,000

7,300,000

Price per MMBtu
$
2.86
$
2.86
$
2.86
$
2.86
$
2.86

(a)
The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price.

(b)
The basis differential price is between Midland – WTI and Cushing – WTI.
(c)
The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

Contents

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, 2017~~March 31, 2020 and ~~2016.~~ ~~The actual historical data in this table excludes results from our acquisition from Reliance Energy, Inc. (the “Reliance Acquisition”) for periods prior to October 2016.~~ 2019. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of ~~our~~ acquisitions orand 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,

2017

2016

2017

2016

Production and operating data:

Average daily production volumes:

Oil (Bbl)


119,565

91,120

115,484

89,854

Natural gas (Mcf)


441,587

370,609

425,791

336,084

Total (Boe)


193,163

152,888

186,449

145,868



Average prices per unit:


Oil, without derivatives (Bbl)

$
45.29

$
41.52

$
46.34

$
37.75

Oil, with derivatives (Bbl) (a)

$
47.81

$
59.87

$
50.45

$
60.74

Natural gas, without derivatives (Mcf)

$
3.18

$
2.42

$
2.96

$
1.97

Natural gas, with derivatives (Mcf) (a)

$
3.22

$
2.46

$
2.94

$
2.14

Total, without derivatives (Boe)

$
35.29

$
30.61

$
35.47

$
27.78

Total, with derivatives (Boe) (a)

$
36.96

$
41.65

$
37.95

$
42.35



Operating costs and expenses per Boe:


Oil and natural gas production

$
5.99

$
4.98

$
5.76

$
6.00

Production and ad valorem taxes

$
2.70

$
2.38

$
2.75

$
2.23

Depreciation, depletion and amortization

$
16.00

$
21.27

$
16.66

$
22.27

General and administrative

$
3.60

$
3.80

$
3.56

$
4.02

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

Three Months Ended

Nine Months Ended




September 30,

September 30,

(in millions)

2017

2016

2017

2016

Net cash receipts from (payments on) derivatives:


Oil derivatives

$
28

$
154

$
129

$
566

Natural gas derivatives

2

1

(3)

16

Total

$
30

$
155

$
126

$
582

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.


	Three Months Ended March 31,
	2020		2019
Production and operating data:
Net production volumes:
Oil (MBbl)	19,020		18,936
Natural gas (MMcf)	63,652		63,769
Total (MBoe)	29,629		29,564

Average daily production volumes:
Oil (MBbl)	209		210
Natural gas (MMcf)	699		709
Total (MBoe)	326		328

Average prices per unit: (a)
Oil, without derivatives (Bbl)	$	45.85	$	49.39
Oil, with derivatives (Bbl) (b)	$	54.88	$	49.56
Natural gas, without derivatives (Mcf)	$	0.79	$	2.64
Natural gas, with derivatives (Mcf) (b)	$	1.25	$	2.59
Total, without derivatives (Boe)	$	31.13	$	37.33
Total, with derivatives (Boe) (b)	$	37.91	$	37.34

Operating costs and expenses per Boe: (a)
Oil and natural gas production	$	5.54	$	5.87
Production and ad valorem taxes	$	2.51	$	2.92
Gathering, processing and transportation	$	1.68	$	0.88
Depreciation, depletion and amortization	$	17.68	$	15.74
General and administrative	$	2.36	$	3.08


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

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

		Three Months Ended March 31,
	(in millions)	2020		2019
	Net cash receipts from (payments on) derivatives:
	Oil derivatives	$	172	$	3
	Natural gas derivatives	29		(3)
	Total	$	201	$	—

	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.

Table of Contents

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016~~

Oil and natural gas revenues. Revenue from oil and natural gas operations was~~$627~~ $922 million for the three months ended ~~September 30, 2017, an increase~~March 31, 2020, a decrease of~~$197~~ $182 million ~~(46~~ (16 percent) from ~~$430~~$1,104 million for ~~2016. This increase~~ 2019. The decrease was primarily due to the ~~increase~~decrease in ~~oil and natural gas production as well as the increase in realized~~ oil and natural gas prices (excluding the effects of derivative activities).

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

·~~average daily~~


	Three Months Ended March 31,
	2020			2019
Net production volumes:
Oil (MBbl)	19,020			18,936
Natural gas (MMcf)	63,652			63,769

Average prices per unit:
Average NYMEX oil price (Bbl)	$	46.35		$	54.87
Realized oil price (Bbl)	$	45.85		$	49.39
Differential to NYMEX	$	(0.50)		$	(5.48)

Average NYMEX natural gas price (MMBtu)	$	1.87		$	2.88
Realized natural gas price (Mcf)	$	0.79		$	2.64
Average realized natural gas price as a percentage of NYMEX	42		%	92		%

•total oil production ~~was 119,565~~ ~~Bbl~~ for the three months ended ~~September 30, 2017, an~~ ~~increase~~ March 31, 2020 was consistent with the same period in 2019 primarily due to additional production from wells completed during 2019 and 2020, offset by the sale of ~~28,445~~ ~~Bbl~~ ~~(31~~ ~~percent) from 91,120~~ ~~Bbl~~ ~~for~~ ~~2016~~;

·our New Mexico Shelf assets in 2019;

•average realized oil price (excluding the effects of derivative activities) ~~was~~ ~~$45.29~~ ~~per Bbl during~~decreased 7 percent for the three months ended ~~September 30, 2017, an increase of 9~~ ~~percent~~ ~~from~~ ~~$41.52~~ ~~per Bbl during~~ ~~2016~~. ~~For the three months ended September 30, 2017, our crude oil price differential relative to NYMEX was $(2.83) per Bbl, or a realization of approximately 94 percent,~~March 31, 2020 as compared to ~~a crude~~the same period in 2019. The decrease in average realized oil price ~~differential relative~~was primarily due to a decrease in the average NYMEX price, partially offset by the narrowing of ~~$(3.51) per Bbl, or a realization of approximately 92 percent, for 2016.~~the basis differential. 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, 2017~~March 31, 2020 and ~~2016,~~2019, the average market ~~basis differential between WTI-Midland~~Mid-Cush differentials was a price benefit of $0.81 per Bbl and ~~WTI-Cushing was~~ a price reduction of $~~0.75~~ ~~per Bbl and $0.31~~ $3.86 per Bbl, respectively. ~~Additionally, we incur fixed deductions from the posted Midland oil price based on the location of our oil within the Permian Basin. These fixed deductions were less per Boe during the~~ ~~three months ended~~ ~~September 30, 2017 as compared to 2016~~ ~~primarily due to more production transported through pipelines;~~

·~~average daily~~

•total natural gas production ~~was 441,587~~ ~~Mcf~~ for the three months ended ~~September 30, 2017, an~~ ~~increase~~ March 31, 2020 was consistent with the same period in 2019 primarily due to additional production from wells completed during 2019 and 2020, offset by the sale of ~~70,978~~ ~~Mcf~~ ~~(19~~ ~~percent) from 370,609~~ ~~Mcf~~ ~~for~~ ~~2016~~;our New Mexico Shelf assets in 2019; and

•average realized natural gas price (excluding the effects of derivative activities) ~~was~~ ~~$3.18~~ ~~per Mcf during~~decreased 70 percent for the three months ended ~~September 30, 2017, an increase of~~March 31, ~~percent~~ ~~from~~ ~~$2.42~~ ~~per Mcf during~~ 2016. For the three months ended September 30, 2017 and 2016, we realized approximately 108 percent and 86 percent, respectively, of the average NYMEX natural gas prices for the respective periods. The increase in our realized natural gas price (excluding the effects of derivatives) as a percentage of NYMEX during the three months ended September 30, 20172020 as compared to ~~2016 was primarily due to an increase~~the same period in ~~the average Mont Belvieu price for~~2019. We derive a ~~blended barrel of natural gas liquids. Historically, and during the~~ ~~three months ended~~ ~~September 30, 2017, we derived a significant~~ portion of our total natural gas revenues from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. The average Mont Belvieu price for a blended barrel of natural gas liquids ~~was~~ ~~$25.04~~ ~~per Bbl and~~ ~~$17.82~~ decreased from $24.13 per Bbl during the three months ended ~~September 30, 2017~~March 31, 2019 to $15.09 per Bbl during the three months ended March 31, 2020. In addition, the continued concerns of rising natural gas production relative to the ability to transport natural gas out of the Permian Basin resulted in the widening of the price differential for natural gas residue during the current period. These widening natural gas residue differentials negatively impacted our realized natural gas prices during both the three months ended March 31, 2020 and ~~2016,~~2019. The combination of these factors resulted in a realized natural gas price of 42 percent and 92 percent of the average NYMEX natural gas price for the three months ended March 31, 2020 and 2019, respectively.

Table of Contents

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, 2017~~March 31, 2020 and ~~2016:~~

2019:

Three Months Ended September 30,

2017

2016

Per

Per
(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

Lease operating expenses

$
100

$
5.68

$
66

$
4.63
Workover costs


6

0.31

5

0.35

Total oil and natural gas production expenses

$
106

$
5.99

$
71

$
4.98


	Three Months Ended March 31,
	2020						2019
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Lease operating expenses	$	156	$	5.27	$	166	$	5.59
Workover costs	8		0.27		8		0.28
Total oil and natural gas production expenses	$	164	$	5.54	$	174	$	5.87

Lease operating expenses were ~~$100~~$156 million ($~~5.68~~5.27 per Boe) for the three months ended ~~September 30, 2017~~,March 31, 2020, which was ~~an increase~~a decrease of ~~$34~~$10 million from ~~$66~~$166 million ($~~4.63~~5.59 per Boe) during ~~2016~~.the same period in 2019. The ~~increase in lease operating expenses during the third quarter of 2017 as compared to 2016~~decrease was primarily due to ~~(i) increased production associated with our~~the New Mexico Shelf divestiture in November 2019, partially offset by additional wells successfully drilled and completed ~~in 2016~~during 2019 and ~~2017, (ii) our acquisitions during the fourth quarter of 2016 and first nine months of 2017 and (iii) an increase in cost of services.~~2020. The ~~increase~~decrease in lease operating expenses per Boe was primarily due to the ~~increase~~New Mexico Shelf divestiture in ~~lease operating expenses noted above~~ ~~including higher expenses~~November 2019.

Workover costs of $8 million ($0.27 per ~~Boe on properties associated~~Boe) for the three months ended March 31, 2020, were consistent with ~~our recent acquisitions in the fourth quarter of 2016 and first nine months of 2017.~~

2019.

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, 2017~~March 31, 2020 and ~~2016:~~

2019:

Three Months Ended September 30,

2017

2016

Per

Per
(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

Production taxes

$
44

$
2.48

$
31

$
2.25
Ad valorem taxes


4

0.22

2

0.13

Total production and ad valorem taxes

$
48

$
2.70

$
33

$
2.38


	Three Months Ended March 31,
	2020						2019
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Production taxes	$	56	$	1.89	$	70	$	2.38
Ad valorem taxes	18		0.62		16		0.54
Total production and ad valorem taxes	$	74	$	2.51	$	86	$	2.92

Production taxes per unit of production were ~~$2.48~~$1.89 per Boe during the three months ended ~~September 30, 2017, an increase~~March 31, 2020, a decrease of 1021 percent from ~~$2.25~~$2.38 per Boe during ~~2016~~.the same period in 2019. Over the same period, our revenue per Boe (excluding the effects of derivatives) ~~increased 15~~decreased 17 percent. The ~~increase~~decrease in production taxes per unit of production was ~~directly related~~primarily 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 $2 million during the three months ended March 31, 2020, as compared to the same period in 2019, primarily due to additional wells drilled and completed, along with a higher percentage of our wells located in Texas, which has higher ad valorem tax rates than New Mexico.

Gathering, processing and transportation costs. The following table shows the gathering, processing and transportation costs for the three months ended March 31, 2020 and 2019:


	Three Months Ended March 31,
	2020						2019
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Gathering, processing and transportation costs	$	50	$	1.68	$	26	$	0.88

Gathering, processing and transportation costs were $50 million ($1.68 per Boe) for the three months ended March 31, 2020, an increase of 92 percent from $26 million ($0.88 per Boe) during same period in 2019. The increase in gathering, processing and transportation costs was primarily due to a marketing contract that began in October 2019 and requires us to deliver 50,000 barrels of oil per day.

Table of Contents

Exploration and abandonments expense. The following table provides the components of our exploration and abandonments expense for the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016:~~

2019:


		Three Months Ended
		September 30,					Three Months Ended March 31,
(in millions)	(in millions)	2017		2016		(in millions)	2020		2019
Geological and geophysical						Geological and geophysical	$	2	$	6
Unproved impairments and leasehold abandonments						Unproved impairments and leasehold abandonments	2,713		30
Other						Other	4		11
Total exploration and abandonments						Total exploration and abandonments	$	2,719	$	47

Geological and geophysical		$	2	$	2
Exploratory dry hole costs			-		-
Leasehold abandonments			5		8
Other			-		-
	Total exploration and abandonments	$	7	$	10

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

~~For~~develop our resources.

We recorded $2,713 million and $30 millionof unproved impairments and leasehold abandonments for the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016, we recorded approximately $5 million~~2019, respectively. Unproved impairments and ~~$8 million, respectively, of~~ leasehold ~~abandonments. For~~abandonments during the three months ended ~~September 30, 2017, our abandonments~~March 31, 2020 were primarily related to ~~drilling locations in~~impairments of certain unproved properties as our ~~Northern Delaware Basin and New Mexico Shelf core areas which, based on multiple factors, are no longer likely to be drilled and acreage in our Southern Delaware Basin core area where we have no~~ future development ~~plans. For~~plans became more uncertain due to significant declines in commodity prices. See Note 4 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information. Leasehold abandonments during the three months ended ~~September 30, 2016, our abandonments~~March 31, 2019 were primarily related to certain expiring ~~acreage.~~

acreage and acreage where we had no future plans to drill located primarily in the Delaware Basin.

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

Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016:~~

2019:

Three Months Ended September 30,

2017

2016

Per

Per
(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

Depletion of proved oil and natural gas properties

$
279

$
15.67

$
294

$
20.88
Depreciation of other property and equipment

5

0.31

5

0.36
Amortization of intangible assets - operating rights

-

0.02

-

0.03

Total depletion, depreciation and amortization

$
284

$
16.00

$
299

$
21.27

Oil price used to estimate proved oil reserves at period end

$
46.27

$
38.17

Natural gas price used to estimate proved natural gas reserves at period end

$
3.00

$
2.28


	Three Months Ended March 31,
	2020						2019
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Depletion of proved oil and natural gas properties	$	515	$	17.39	$	457	$	15.47
Depreciation of other property and equipment	8		0.28		7		0.24
Amortization of intangible assets	1		0.01		1		0.03
Total depletion, depreciation and amortization	$	524	$	17.68	$	465	$	15.74

Oil price used to estimate proved oil reserves at period end	$	52.23			$	59.52
Natural gas price used to estimate proved natural gas reserves at period end	$	2.30			$	3.07

Depletion of proved oil and natural gas properties was ~~$279~~$515 million ($~~15.67~~17.39 per Boe) for the three months ended ~~September 30, 2017 and $294~~March 31, 2020, an increase of $58 million (13 percent) from $457 million ($~~20.88~~15.47 per Boe) for ~~2016.~~2019. The ~~decrease~~increase in depletion expense was primarily due to ~~a lower~~the increase in depletion rate per ~~Boe period over period partially offset by an~~Boe. The increase ~~in production. The decrease~~ in depletion expense per Boe ~~period over period~~ was primarily due to ~~(i) lower drilling and completion costs per Boe of proved developed reserves added and (ii) an overall increase in proved reserves period over period primarily due~~certain downward adjustments to our successful exploratory drilling program, the Reliance Acquisition, the Northern Delaware Basin acquisition, the Midland Basin acquisition, reductions in future estimated lease operating expenses and an increase in commodity prices period over period, partially offset by decreased proved reserves caused by reclassification of proved undeveloped reserves to unproved reserves because they are no longer expected to be developed within five years of their initial recording.

~~Impairments of long-lived assets.~~ ~~We periodically review our long-lived assets to be held and used, including~~economically recoverable proved oil and natural gas ~~properties and their integrated assets, whenever events or circumstances indicate that~~reserves during 2019.

Impairments of long-lived assets. During the ~~carrying~~three months ended March 31, 2020, we recognized impairment charges of approximately $7.8 billion attributable to the significant decrease in value of ~~those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. We~~

~~review~~ our proved oil and natural gas ~~properties by depletion base. An impairment loss is indicated if~~reserves in both the ~~sum of~~Midland Basin and Delaware Basin primarily due to the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of our assets, we recognize an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.

~~We estimate undiscounted future net cash flows of our long-lived assets and their integrated assets using management’s assumptions and expectations of (i)~~significant decline in commodity prices, which are based on the NYMEX strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, and (vii) prevailing market rates of income and expenses from integrated assets. At September 30, 2017, our estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a 2017 price of $~~52.29~~ ~~per barrel of oil decreasing to a 2021 price of $50.77 per barrel of oil partially recovering to a 2024 price of $52.01~~ ~~per barrel of oil. Similarly, natural gas prices ranged from a 2017 price of $3.14~~ ~~per Mcf of natural gas decreasing to a 2020 price of $2.85~~ ~~per Mcf of natural gas partially recovering to a 2024 price of $2.88~~ ~~per Mcf of natural gas. Commodity prices for this purpose were held flat after 2024.~~

We estimate fair values of our long-lived assets and their integrated assets using a discounted future cash flow model. Fair value assumptions associated with the calculation of discounted future net cash flows include (i) market estimates of commodity prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, (vii) prevailing market rates of income and expenses from integrated assets and (viii) discount rate. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value.prices. We did not recognize an impairment charge during the three months ended ~~September 30, 2017 or 2016.~~

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

Based on economic factors at September 30, 2017, we determined that undiscounted future cash flows attributable to our North Basin Bone Spring (“NBBS”) field located in the Northern Delaware Basin with a net book value of approximately $~~1.1~~ billion indicated that its carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows). We estimate that if the future oil and natural gas prices used in this analysis, and noted above, would have been approximately 10 percent lower at September 30, 2017 with no other changes in capital costs, operating costs, price differentials, or reserve performance curves, we could have recognized a non-cash impairment in that period of approximately $470 million related to our NBBS field. 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 someMarch 31, 2019. See Note 4 of the ~~effects~~Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on the fair value assumptions used for long-lived assets.

Table of Contents

Impairments of goodwill. At March 31, 2020, we performed a ~~reduction in commodity prices, including the ultimate impact~~goodwill impairment test and ~~amount~~impaired our entire goodwill balance of ~~any potential~~$1.9 billion. The impairment ~~charge. As a result, we are unable~~was primarily due to ~~predict with certainty whether or not~~ a decline in ~~commodity prices alone will cause us~~our market capitalization along with declines in observable control premiums. See Note 2 of the Condensed Notes to ~~recognize an~~Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on the impairment ~~charge in a particular field or the magnitude~~ of any such impairment charge. We additionally note that there may be changes to both drilling and completion designs that affect the volume curves, capital costs estimates, and the amount of proved undeveloped locations that can be recorded, each of which will affect management’s estimates of future cash flows.

goodwill.

General and administrative expenses.The following table provides components of our general and administrative expenses for the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016:~~

2019:

Three Months Ended September 30,

2017

2016

Per

Per
(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

General and administrative expenses

$
51

$
2.89

$
42

$
3.04
Less: Operating fee reimbursements


(4)

(0.24)

(4)

(0.29)
Non-cash stock-based compensation


17

0.95

15

1.05

Total general and administrative expenses

$
64

$
3.60

$
53

$
3.80

~~General~~


	Three Months Ended March 31,
	2020						2019
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
General and administrative expenses	$	56	$	1.88	$	71	$	2.40
Less: Operating fee reimbursements	(5)		(0.15)		(4)		(0.13)
Non-cash stock-based compensation	18		0.63		24		0.81
Total general and administrative expenses	$	69	$	2.36	$	91	$	3.08

Total general and administrative expenses were ~~approximately $64~~$69 million ($~~3.60~~2.36 per Boe) for the three months ended ~~September 30, 2017, an increase~~March 31, 2020, a decrease of ~~$11~~$22 million ~~(21~~(24 percent) from ~~$53~~$91 million ($~~3.80~~3.08 per Boe) ~~for~~ ~~2016~~.during the same period in 2019. The ~~increase~~decrease in cash general and administrative expenses was primarily ~~driven by increased~~due to lower variable compensation ~~expense as a result of increased~~accruals and lower employee headcount. The ~~increase~~decrease in non-cash stock-based compensation expenses was primarily due to ~~the increase in~~lower employee headcount ~~coupled~~and higher forfeitures during 2020, and lapse of restrictions of certain equity awards in July 2019 that were granted in conjunction with ~~lower forfeitures in~~ the ~~third quarter~~acquisition of ~~2017.~~ RSP Permian, Inc. The decrease in total general and administrative expenses per Boe was primarily ~~due to increased production period over period, partially offset by~~ the ~~increase~~result of the decrease in general and administrative ~~costs~~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 inon the consolidated statements of operations. We earned reimbursements of ~~approximately~~ $4$5 million ~~for each of~~and $4 million during the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016~~.

2019, respectively.

Gain (loss) on derivatives.The following table sets forth the gain (loss) on derivatives for the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016:~~

2019:


			Three Months Ended
			September 30,					Three Months Ended March 31,
(in millions)	(in millions)			2017		2016	(in millions)	2020		2019
Gain (loss) on derivatives:							Gain (loss) on derivatives:
Oil derivatives							Oil derivatives	$	1,825	$	(1,056)
Natural gas derivatives							Natural gas derivatives	(56)		(3)
Total							Total	$	1,769	$	(1,059)

*Gain (loss) on derivatives:*
	Oil derivatives		$	(205)	$	36
	Natural gas derivatives			(1)		5
		Total	$	(206)	$	41


The following table represents our net cash receipts from derivatives for the three months ended September 30, 2017 and 2016:


			Three Months Ended
			September 30,
(in millions)				2017		2016

*Net cash receipts from derivatives:*
	Oil derivatives		$	28	$	154
	Natural gas derivatives			2		1
		Total	$	30	$	155

The following table represents our net cash receipts from (payments on) derivatives for the three months ended March 31, 2020 and 2019:


	Three Months Ended March 31,
(in millions)	2020		2019
Net cash receipts from (payments on) derivatives:
Oil derivatives	$	172	$	3
Natural gas derivatives	29		(3)
Total	$	201	$	—

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,~~gains; while to the extent the future commodity price outlook increases between measurement periods, we will have mark-to-market losses. See Note 64 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.

Table of Contents

Interest expense.~~Interest~~ The following table sets forth interest expense, ~~was $39 million~~weighted average interest rates and weighted average debt balances for the three months ended ~~September 30, 2017~~March 31, 2020 and 2019:


	Three Months Ended March 31,
(in millions)	2020			2019
Interest expense, as reported	$	42		$	47
Capitalized interest	5			4
Interest expense, excluding impact of capitalized interest	$	47		$	51

Weighted average interest rate - credit facility	3.1		%	4.4		%
Weighted average interest rate - senior notes	4.4		%	4.4		%
Total weighted average interest rate	4.4		%	4.4		%

Weighted average credit facility balance	$	40		$	503
Weighted average senior notes balance	4,000			4,000
Total weighted average debt balance	$	4,040		$	4,503

The decrease in interest expense during the three months ended March 31, 2020 as compared to $53 ~~million during 2016. The decrease~~2019 was primarily due to ~~(i) approximately $11 million of interest expense related to our $600 million 7.0% unsecured senior notes due 2021 (the “7.0% Notes”) that were redeemed~~the decrease in September 2016 and (ii) approximately $10 million of interest expense related to our $600 million 6.5% unsecured senior notes due 2022 (the “6.5% Notes”) that were satisfied and discharged in December 2016, partially offset by approximately $7 million of interest expense related to our $600 million 4.375% unsecured senior notes due 2025 (the “4.375% Notes”) issued in December 2016.

~~Loss on extinguishment of debt.~~~~We recorded a loss on extinguishment of debt of approximately $65 million for~~the weighted average Credit Facility balance.

Other, net. During the three months ended ~~September 30, 2017. This amount includes approximately $36~~March 31, 2020, we recorded other expense of $195 million, ~~associated with the premium paid for the Tender Offer, approximately $25~~primarily due to a $204 million ~~associated with the make-whole premium paid for the early extinguishment~~other than temporary impairment 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.

We recorded a loss on extinguishment of debt of approximately $28 million for the three months ended September 30, 2016. This amount includes $21 million associated with the make-whole premium paid for the early redemption of our 7.0% Notes and approximately $7 million of unamortized deferred loan costs.

an equity method investment.

Income tax provisions. We recorded an income tax benefit of ~~$66 million~~$1.6 billion and ~~$30~~$194 million for the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, respectively. ~~The change in our income tax provision was primarily due to the increase in our net loss before income taxes. The effective income tax rates for the three months ended~~ ~~September 30, 2017~~ ~~and 2016 were 36.7 percent and 37.3 percent, respectively.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016~~

~~Oil and natural gas revenues.~~ ~~Revenue from oil and natural gas operations was$1,806 million for the nine months ended~~ ~~September 30, 2017, an increase of$696 million (63~~ ~~percent) from $1,110 million for~~ ~~2016~~. 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). Specific factors affecting oil and natural gas revenues include the following:

·~~average daily oil production was 115,484~~ ~~Bbl~~ ~~for the nine months ended~~ ~~September 30, 2017, an~~ ~~increase~~ ~~of 25,630~~ ~~Bbl~~ ~~(29~~ ~~percent) from 89,854~~ ~~Bbl~~ ~~for~~ ~~2016~~;

·~~average realized oil price (excluding the effects of derivative activities) was~~ ~~$46.34~~ ~~per Bbl during the nine months ended~~ ~~September 30, 2017, an increase of 23~~ ~~percent~~ ~~from~~ ~~$37.75~~ ~~per Bbl during~~ ~~2016~~. For the nine months ended September 30, 2017, our crude oil price differential relative to NYMEX was $(3.11) per Bbl, or a realization of approximately 94 percent, as compared to a crude oil price differential relative to NYMEX of $(3.70) per Bbl, or a realization of approximately 91 percent, for 2016. The basis 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, 2017 and 2016, the average market basis differential between WTI-Midland and WTI-Cushing was a price reduction of $0.31 per Bbl and $0.11 per Bbl, respectively. Additionally, we incur fixed deductions from the posted Midland oil price based on the location of our oil within the Permian Basin. These fixed deductions were less per Boe during the nine months ended September 30, 2017 as compared to 2016 primarily due to more production transported through pipelines and successful renegotiation of fixed deductions for trucked volumes;

·~~average daily natural gas production was 425,791~~ ~~Mcf~~ ~~for the nine months ended~~ ~~September 30, 2017, an~~ ~~increase~~ ~~of 89,707~~ ~~Mcf~~ ~~(27~~ ~~percent) from 336,084~~ ~~Mcf~~ ~~for~~ ~~2016; and~~

·~~average realized natural gas price (excluding the effects of derivative activities) was~~ ~~$2.96~~ ~~per Mcf during the nine months ended~~ ~~September 30, 2017, an increase of 50~~ ~~percent~~ ~~from~~ ~~$1.97~~ ~~per Mcf during~~ ~~2016. For the nine months ended~~ ~~September 30, 2017 and 2016, we realized approximately 97 percent and 84 percent, respectively, of the average NYMEX natural gas prices for the respective periods.~~ ~~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, 2017 as compared to 2016 was primarily due to an increase in the average Mont Belvieu price for a blended barrel of natural gas liquids. Historically, and during the~~ ~~nine~~ months ended September 30, 2017, we derived a significant portion of our total natural gas revenues from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. The average Mont Belvieu price for a blended barrel of natural gas liquids was ~~$23.74~~ ~~per Bbl and~~ ~~$16.82~~ ~~per Bbl during the nine months ended September 30, 2017 and 2016, respectively.~~

During December 2015, a third-party natural gas processing plant located in the Northern Delaware Basin became inoperable following an explosion. We estimate that this event negatively impacted production for the nine months ended September 30, 2016 by approximately 1.6 MBoepd. The plant became fully operational during April 2016.

~~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, 2017 and 2016:~~

Nine Months Ended September 30,

2017

2016

Per

Per
(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

Lease operating expenses

$
278

$
5.47

$
225

$
5.62
Workover costs


15

0.29

15

0.38

Total oil and natural gas production expenses

$
293

$
5.76

$
240

$
6.00

~~Lease operating expenses were $278 million ($5.47 per Boe) for the nine months ended~~ ~~September 30, 2017, which was an increase of $53 million from $225 million ($5.62 per Boe) during~~ ~~2016. The increase in lease operating expenses during the nine months ended~~ ~~September 30, 2017~~ as compared to 2016 was primarily due to (i) increased production associated with our wells successfully drilled and completed in 2016 and 2017, (ii) our acquisitions during the fourth quarter of 2016 and first nine months of 2017 and (iii) increased cost of services, partially offset by a decrease in facility expense. The decrease in lease operating expenses per Boe was primarily due to increased production during the first nine months of 2017 as compared to 2016, partially offset by the increase in total lease operating expenses as noted above.

~~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, 2017~~ ~~and 2016:~~

Nine Months Ended September 30,

2017

2016

Per

Per
(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

Production taxes

$
128

$
2.52

$
78

$
1.96
Ad valorem taxes


12

0.23

11

0.27

Total production and ad valorem taxes

$
140

$
2.75

$
89

$
2.23

~~Production taxes per unit of production were $2.52 per Boe during the nine months ended~~ ~~September 30, 2017, an increase of 29 percent from $1.96 per Boe during~~ ~~2016~~. 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. Additionally, tax credits of approximately $4 million were received during the first quarter of 2016 related to certain wells in Texas qualifying for reduced severance tax rates. 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.

~~Exploration and abandonments expense.~~ ~~The following table provides the components of our exploration and abandonments expense for the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2017~~ ~~and 2016:~~

Nine Months Ended

September 30,
(in millions)

2017

2016

Geological and geophysical

$
9

$
6
Exploratory dry hole costs


-

7
Leasehold abandonments

29

40
Other


4

1

Total exploration and abandonments

$
42

$
54

~~Our geological and geophysical expense for the periods presented above primarily consists of the costs of acquiring and processing geophysical data and core analysis.~~

Our exploratory dry hole costs during the nine months ended September 30, 2016 were primarily related to an uneconomic well in our Northern Delaware Basin core area that was attempting to establish commercial production through testing of multiple zones. We did not recognize any exploratory dry hole costs during the nine months ended September 30, 2017.

~~For the~~ ~~nine~~ ~~months ended September 30, 2017 and 2016, we recorded approximately $29 million and $40 million, respectively, of leasehold abandonments. For the~~ ~~nine~~ months ended September 30, 2017, our abandonments were primarily related to (i) non-contiguous acreage expiring in our Southern Delaware Basin core area and (ii) acreage in our Northern Delaware Basin and New Mexico Shelf core areas in locations where we have no future plans to drill. For the ~~nine~~ months ended September 30, 2016, our abandonments were primarily related to (i) drilling locations in our Northern Delaware Basin and New Mexico Shelf core areas which, based on multiple factors, are no longer likely to be drilled, (ii) acreage in our Northern Delaware Basin and New Mexico Shelf core areas where we have no future development plans and (iii) expiring acreage.

~~Depreciation, depletion and amortization expense.~~ ~~The following table provides components of our depreciation, depletion and amortization expense for the nine months ended~~ ~~September 30, 2017~~ ~~and 2016:~~

Nine Months Ended September 30,

2017

2016

Per

Per
(in millions, except per unit amounts)


Amount

Boe

Amount

Boe

Depletion of proved oil and natural gas properties

$
830

$
16.31

$
874

$
21.86
Depreciation of other property and equipment


17

0.33

15

0.38
Amortization of intangible assets - operating rights


1

0.02

1

0.03

Total depletion, depreciation and amortization

$
848

$
16.66

$
890

$
22.27

~~Depletion of proved oil and natural gas properties was $830 million ($16.31 per Boe) for the nine months ended~~ ~~September 30, 2017, a decrease of $44 million (5 percent) from $874 million ($21.86 per Boe) for~~ ~~2016~~. The decrease in depletion expense was primarily due to a lower depletion rate per Boe period over period partially offset by an increase in production. The decrease in depletion expense per Boe period over period was primarily due to (i) lower drilling and completion costs per Boe of proved developed reserves added, (ii) an overall increase in proved reserves period over period primarily caused by our successful exploratory drilling program, the Reliance Acquisition, the Northern Delaware Basin acquisition, the Midland Basin acquisition, reductions in future estimated lease operating expenses and higher commodity prices period over period, partially offset by decreased proved reserves caused by reclassification of proved undeveloped

reserves to unproved reserves because they are no longer expected to be developed within five years of their initial recording and (iii) a non-cash impairment charge of approximately $1.5 billion recorded in the first quarter of 2016.

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

We estimate undiscounted future net cash flows of our long-lived assets and their integrated assets using management’s assumptions and expectations of (i) commodity prices, which are based on the NYMEX strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, and (vii) prevailing market rates of income and expenses from integrated assets. At September 30, 2017, our estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a 2017 price of $~~52.29~~ ~~per barrel of oil decreasing to a 2021 price of $50.77~~ ~~per barrel of oil partially recovering to a 2024 price of $52.01~~ ~~per barrel of oil. Similarly, natural gas prices ranged from a 2017 price of $3.14~~ ~~per Mcf of natural gas decreasing to a 2020 price of $2.85~~ ~~per Mcf of natural gas partially recovering to a 2024 price of $2.88~~ ~~per Mcf of natural gas. Commodity prices for this purpose were held flat after 2024.~~

During the three months ended March 31, 2016, NYMEX strip prices declined as compared to December 31, 2015, and as a result the carrying amount of our Yeso field in our New Mexico Shelf core area exceeded the expected undiscounted future net cash flows resulting in a non-cash charge against earnings of approximately $1.5 billion. The Yeso field, as compared to our other fields not previously impaired, had significant proved reserves upon acquisition, which required a higher valuation than a field more exploratory in nature that has a higher risk factor adjustment in the fair value estimate. Our estimates of commodity prices for purposes of determining the estimated fair value at March 31, 2016 ranged from a 2016 price of $41.26 per barrel of oil and $2.26 per Mcf of natural gas to a 2023 price of $66.33 per barrel of oil and $3.56 per Mcf of natural gas. Commodity prices for this purpose were held flat after 2023. We did not recognize an impairment charge during the nine months ended September 30, 2017.

~~Based on economic factors at September 30, 2017,~~2020, we ~~determined that undiscounted future cash flows attributable to our NBBS field located in the Northern Delaware Basin with a net book value of approximately $1.1~~ billion indicated that its carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows). We estimate that if the future oil and natural gas prices used in this analysis, and noted above, would have been approximately 10 percent lower at September 30, 2017 with no other changes in capital costs, operating costs, price differentials, or reserve performance curves, we could have recognized a non-cash impairment in that period of approximately $470 million related to our NBBS field. 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 cause us to recognize an impairment charge in a particular field or the magnitude of any such impairment charge. We additionally note that there may be changes to both drilling and completion designs that affect the volume curves, capital costs estimates, and the amountrecorded impairments of proved ~~undeveloped locations that can be recorded, each of which will affect management’s estimates of future cash flows.~~

~~General~~ and ~~administrative expenses.~~~~The following table provides components of our general and administrative expenses for the nine months ended~~ ~~September 30, 2017~~ ~~and 2016:~~

Nine Months Ended September 30,

2017

2016

Per

Per
(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

General and administrative expenses

$
149

$
2.95

$
129

$
3.24
Less: Operating fee reimbursements


(12)

(0.24)

(12)

(0.30)
Non-cash stock-based compensation


43

0.85

43

1.08

Total general and administrative expenses

$
180

$
3.56

$
160

$
4.02

~~General and administrative expenses were approximately $180 million ($3.56 per Boe) for the nine months ended~~ ~~September 30, 2017, an increase of $20 million (13 percent) from $160 million ($4.02 per Boe) for~~ ~~2016~~. The increase in cash general and administrative expenses was primarily a result of increased compensation expense. The decrease in total general and administrative expenses per Boe was primarily due to increased production period over period, partially offset by the increase in general and administrative costs noted above.

~~We receive fees for the operation of jointly-owned~~unproved oil and natural gas properties ~~during~~of $7.8 billion and $2.7 billion, respectively, which caused our deferred tax balance to change from a net deferred tax liability to the ~~drilling and production phases and record such reimbursements as reductions of general and administrative expenses~~net deferred tax asset, resulting in the ~~consolidated statements~~establishment of ~~operations.~~a valuation allowance against our deferred tax assets at March 31, 2020. We ~~earned reimbursements of approximately $12 million~~recognized the valuation allowance as an ordinary item in our estimated annual effective tax rate.

Our effective income tax rates were 14 percent and 22 percent for ~~each of~~ the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016.~~

~~Gain (loss) on derivatives.~~2019, respectively. The ~~following table sets forth~~difference between the ~~gain (loss) on derivatives~~U.S federal statutory rate of 21 percent and our effective tax rate for the ~~nine~~three months ended ~~September 30, 2017~~ ~~and 2016:~~

Nine Months Ended

September 30,
(in millions)

2017

2016

Gain (loss) on derivatives:

Oil derivatives

$
260

$
(173)

Natural gas derivatives

29

(3)

Total

$
289

$
(176)

     The following table represents our net cash receipts from (payments on) derivatives for the nine months ended September 30, 2017 and 2016:

Nine Months Ended

September 30,
(in millions)

2017

2016

Net cash receipts from (payments on) derivatives:

Oil derivatives

$
129

$
566

Natural gas derivatives


(3)


16

Total

$
126

$
582

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent the future commodity price outlook increases between measurement periods, we will have mark-to-market losses. See Note 6 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding significant judgments made in classifying financial instruments in the fair value hierarchy.

~~Gain on disposition of assets, net.~~ In February 2017, we closed on our previously announced 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.~~

~~In February 2016, we sold certain assets in the Northern Delaware Basin for proceeds of approximately $292 million and recognized a pre-tax gain of approximately $110 million.~~

~~Interest expense.~~ ~~Interest expense was $118 million for the nine months ended~~ ~~September 30, 2017 as compared to $162~~ ~~million during 2016. The decrease~~March 31, 2020 was primarily due to ~~(i) approximately $32 million~~the impact of ~~interest expense related to our $600 million 7.0% Notes that were redeemed~~the nondeductible goodwill impairment reported discretely, the change in ~~September 2016~~valuation allowance and ~~(ii) approximately $29 million~~the impact of ~~interest expense related to our $600 million 6.5% Notes that were satisfied and discharged in December 2016,~~permanent differences, partially offset by ~~approximately $20 million~~state income taxes. The difference between the U.S federal statutory rate of ~~interest expense related to~~21 percent and our ~~$600 million 4.375% Notes issued in December 2016.~~

~~Loss on extinguishment of debt.~~ ~~We recorded a loss on extinguishment of debt of approximately $66 million~~effective tax rate for the ~~nine~~three months ended September 30, 2017. This amount includes (i) approximately $36 million associated with the premium paid for the Tender Offer, 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.

~~We recorded a loss on extinguishment of debt of approximately~~ $28 million for the nine months ended September 30, 2016. This amount includes $21 million associated with the make-whole premium paid for the early redemption of the 7.0% Notes and approximately $7 million of unamortized deferred loan costs.

~~Income tax provisions.~~ We recorded income tax expense of $398 million, which includes a discrete income tax benefit of approximately $6 million related to excess tax benefits on stock-based awards, which are recorded in the income tax provision pursuant to ASU No. 2016-09, which was adopted on January 1, 2017, and an income tax benefit of $782 million for the nine months ended September 30, 2017 and 2016, respectively. The change in our income tax provisionMarch 31, 2019 was primarily due to ~~income before~~state income taxes ~~during~~and the ~~nine months ended September 30, 2017, as compared~~impact of permanent differences, partially offset by research and development credits, net of unrecognized tax benefits. At the end of each interim period, we apply an estimated annualized effective tax rate to athe current period income or loss before income taxes, ~~during 2016. The~~which can produce interim effective ~~income~~ tax ~~rates for the nine months ended September 30, 2017 and 2016 were 36.6 percent and 36.9 percent, respectively.~~

rate fluctuations.

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Capital Commitments, Capital Resources and Liquidity

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

~~Oil~~

2020 capital budget and costs incurred.In March 2020, in response to the substantial decrease in oil and natural gas ~~properties.~~ prices, we announced that we reduced our 2020 planned capital expenditures to approximately $1.6 billion from the $2.6 billion to $2.8 billion range previously announced. Based on our current expectations of commodity prices and cost, we expect to fund our 2020 capital budget primarily with operating cash flows. However, if we experience sustained commodity prices lower than our forecasted pricing without sufficient costs reductions, we may adjust our capital budget to preserve our financial strength.

Despite the change to our planned capital expenditures for 2020, our proved undeveloped reserves reported in our Annual Report on Form 10-K for the year ended December 31, 2019 remain scheduled to be drilled within five years of the date of their initial recognition.

Our costs incurred on oil and natural gas properties, excluding acquisitions, during the ~~nine~~three months ended ~~September 30, 2017~~ ~~and 2016~~March 31, 2020 totaled ~~$1.2 billion and $800 million, respectively. The increase was primarily due to our increased drilling and completion activity level~~$567 million. Our capital expenditures during the ~~first nine~~three months of 2017 as compared to 2016. Our intent is to manage our capital spending to be within our cash flow, excluding unbudgeted acquisitions. The primary reason for the differences in costs incurred and cash flow expenditures was our issuance of approximately 2.2 million shares of common stock related to our Northern Delaware Basin acquisition and timing of payments. Total 2017 expendituresended March 31, 2020 were primarily funded ~~in part~~ from ~~(i)~~ cash flows from ~~operations, (ii)~~operations.

During the remainder of 2020, we expect to fund our ~~issuance of approximately 2.2 million shares of common stock related to our Northern Delaware Basin acquisition and to a lesser extent (iii) proceeds from our February 2017 divestiture of ACC.~~

~~2017 capital budget.~~ ~~In February 2017, we announced our updated 2017~~2020 capital budget ~~excluding acquisitions, of approximately $1.8 billion~~ with expected capital spending to range between $1.6 billion and $1.8 billion. Approximately 90 percent of capital will be directed to drilling and completion activity. Our 2017 capital program, based on our current expectations of commodity prices and costs, is expected to be within ouroperating cash flows. ~~However, if we were to outspend our cash flows, we believe we could use our credit facility and other financing sources to fund any cash flow deficits.~~ The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the costs of drilling rigs and other services and equipment, regulatory, technological and competitive developments ~~commodity prices, leverage metrics~~ and ~~industry~~market conditions. In addition, under certain circumstances, we may consider increasing, decreasing or reallocating our capital spending plans.

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

2020 dividends. On April 28, 2020, our board of directors approved a cash dividend of $0.20 per share for the second quarter of 2020 that is expected to be paid on June 26, 2020 to stockholders of record as of May 8, 2020. Total cash dividends paid to our stockholders during the three months ended March 31, 2020 were $39 million. We intend to continue to pay a quarterly dividend of $0.20 per share in the near future; however, any payment of future dividends will be at the discretion of our board of directors and may be suspended at any time.

Share repurchase program. In September 2019, we announced that our board of directors authorized the initiation of a share repurchase program for up to $1.5 billion of our common stock. The share repurchase program may be modified, suspended or terminated at any time by our board of directors and we are not obligated to acquire any specific number of shares.

During January 2020, the Company repurchased and retired 1,125,906 shares under the program at an aggregate cost of $100 million. As of March 31, 2020, the Company had repurchased and retired a total of 4,426,276 shares since the inception of the program at an aggregate cost of $350 million.

Acquisitions.The following table reflects ourour expenditures for acquisitions of proved and unproved properties for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016:~~

2019:


			Nine Months Ended
			September 30,					Three Months Ended March 31,
(in millions)	(in millions)		2017		2016		(in millions)	2020		2019
Property acquisition costs:							Property acquisition costs:
Proved							Proved	$	7	$	—
Unproved (a)							Unproved (a)	5		4
Total property acquisition costs							Total property acquisition costs	$	12	$	4

Property acquisition costs:
	Proved		$	301	$	257
	Unproved			865		172
		Total property acquisition costs (a)	$	1,166	$	429


(a)	Included in the property acquisition costs above are budgeted unproved leasehold acreage acquisitions of approximately td6 million for each of the nine months ended September 30, 2017 and 2016. 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. For the nine months ended September 30, 2016, our unbudgeted acquisitions are primarily comprised of approximately $375 million of property acquisition costs related to our Southern Delaware Basin acquisition.




(a) Unproved property acquisition costs relate primarily to budgeted unproved leasehold acreage acquisitions.							(a) Unproved property acquisition costs relate primarily to budgeted unproved leasehold acreage acquisitions.

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Contractual obligations.Our contractual obligations include long-term debt, cash interest expense on debt, derivative liabilities, asset retirement obligations, employment agreements with officers, purchase obligations, operating and finance lease obligations and other obligations. Since December 31, ~~2016, the~~2019, there have been no material changes in our contractual obligations, ~~are not material,~~ other than ~~our cash interest expense on debt and~~the decrease in our derivative liability ~~position. Cash interest expense on debt increased by $854 million due to the issuance of the Notes~~ which ~~have maturity dates of 2027 and 2047, as compared to the retired 5.5% Notes~~

~~which had maturity dates of 2022 and 2023. Our derivative liability position decreased from December~~was zero at March 31, 2016 by $135 million. See Note 8 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our long-term debt and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for information regarding the interest on our long-term debt and information on changes in the fair value of our open derivative obligations during the nine months ended ~~September 30, 2017~~.

2020.

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,~~Credit Facility, (iii) asset dispositions and (iv) proceeds from bond and equity ~~offerings~~offerings. In March 2020, in response to the substantial decrease in oil and ~~(iv) asset dispositions. In February 2017,~~natural gas prices, we announced that we reduced our ~~updated 2017~~2020 planned capital ~~budget, excluding acquisitions, of~~expenditures to approximately ~~$1.8 billion with expected capital spending to range between~~ $1.6 billion ~~and $1.8 billion. Our 2017 capital program, based~~from the $2.6 billion to $2.8 billion range previously announced. Based on our current expectations of commodity prices and ~~costs, is expected~~cost, we expect to ~~be within~~fund our 2020 capital budget primarily with operating cash flows. However, if we were to outspend our cash flows, we believe we could use our credit facility and other financing sources to fund any cash flow deficits. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the costs of drilling rigs and other services and equipment, regulatory, technological and competitive developments,experience sustained commodity prices ~~leverage metrics and industry conditions. In addition, under certain circumstances,~~lower than our forecasted pricing without sufficient costs reductions, we may ~~consider increasing, decreasing or reallocating~~adjust our capital ~~spending plans.~~

budget to preserve our financial strength. At March 31, 2020, we had a cash balance of $165 million and did not have any borrowings under our Credit Facility. As of March 31, 2020, we had approximately $2.0 billion of unused commitments under our Credit Facility.

The following table summarizes our changes in cash and cash equivalents for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016:~~

2019:


		Nine Months Ended
		September 30,					Three Months Ended March 31,
(in millions)	(in millions)	2017		2016		(in millions)	2020		2019

Net cash provided by operating activities	Net cash provided by operating activities	$	1,185	$	1,019	Net cash provided by operating activities	$	836	$	623
Net cash used in investing activities	Net cash used in investing activities		(1,207)		(783)	Net cash used in investing activities	(596)		(902)
Net cash provided by (used in) financing activities	Net cash provided by (used in) financing activities		(31)		694	Net cash provided by (used in) financing activities	(145)		279
Net increase in cash and cash equivalents						Net increase in cash and cash equivalents	$	95	$	—
	Net increase (decrease) in cash and cash equivalents	$	(53)	$	930

Cash flow from operating activities.The $213 million increase in operating cash flows during the ~~nine~~ three months ended ~~September 30, 2017~~March 31, 2020 as compared to the same period in ~~2016~~2019 was primarily due to an increase of $201 million in net cash settlements received from derivatives, partially offset by the decrease in oil and natural gas ~~revenues of approximately $696 million and a decrease in cash interest expense of approximately $42 million, partially offset by (i)~~ ~~approximately $126~~ ~~million from settlements on derivatives during the nine months ended September 30, 2017, as compared to $582~~ ~~million from settlements on derivatives during the comparable period in 2016,~~ (ii) approximately $53 million increase in production expense, (iii) approximately $51 million increase in production tax expense and (iv) a decrease in operating cash flow of approximately $20 million due to cash tax expense of approximately $6 million for the ~~nine~~ ~~months ended September 30, 2017, as compared to a cash tax benefit of approximately $14 million during the comparable period in 2016.~~

revenues.

Our net cash provided by operating activities included a benefit of $92 million and a reduction of ~~approximately $59million and $73~~$78 million for the ~~nine~~ three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, 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.

For the ~~nine~~three months ended ~~September 30, 2017~~ ~~and 2016, we invested approximately $1,958~~March 31, 2020, our net cash used in investing activities was $596 million, ~~and $927~~which consisted primarily of our investment of $556 million ~~respectively,~~ for ~~capital expenditures on~~additions to oil and natural gas properties. Additionally, we ~~received approximately $803~~ ~~million related to proceeds from~~completed acquisitions of oil and natural gas properties of $20 million. Our capital expenditures for the ~~disposition of assets during the nine~~three months ended ~~September 30, 2017,~~ ~~as compared~~March 31, 2020 were funded with cash flows from operations.

For the three months ended March 31, 2019, our net cash used in investing activities was $902 million, which consisted primarily of our investment of $918 million for additions to $~~296~~ ~~million during~~oil and natural gas properties. Our capital expenditures for the ~~comparable period of 2016.~~

three months ended March 31, 2019 were funded with cash flows from operations and borrowings under our Credit Facility.

Cash flow from financing activities.~~Net~~ For the three months ended March 31, 2020, our net cash used in financing activities was ~~approximately $31~~$145 million ~~for~~primarily due to $100 million of common stock repurchases under our share repurchase program and $39 million of dividends paid on our common stock.

For the ~~nine~~ three months ended ~~September 30, 2017 while~~March 31, 2019, our net cash provided by financing activities was ~~approximately $694~~$279 million ~~for the~~ ~~nine~~ ~~months ended September 30, 2016. Below is a description~~primarily due to $373 million of ~~our significant financing activities:~~

·~~In September 2017, we issued $1,800 million in aggregate principal amount of the Notes, 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) 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, approximatelyCredit Facility partially offset by $25 million ~~for the make-whole premium~~of dividends paid ~~for the early extinguishment of the 5.5% Notes and approximately $2 million for prepaid interest as part of the satisfaction and discharge.~~

·In September 2016, we redeemed the $600 million outstanding principal amount of our 7.0% Notes at a price equal to 103.5 percent of par. The redemption price included the make-whole premium for the early redemption of $21 million.

·~~In August 2016, we issued approximately 10.4 million shares of~~on our common ~~stock in a public offering at $130.90 per share and received net proceeds of approximately $1.3 billion.~~

·stock. During the ~~first nine~~three months of ~~2017~~,ended March 31, 2019, we ~~borrowed $368 million on~~decreased our ~~credit facility.~~

·~~During the first nine months of~~ ~~2016, we had no outstanding borrowings under our credit facility.~~

~~In April 2017, we amended our credit facility to decrease our unused lender commitments.~~ At ~~September 30, 2017,~~ ~~we had unused commitments on our credit facility of approximately~~ ~~$1.6~~ ~~billion.~~

book overdrafts by $54 million.

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

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

(a) the prime rate of JPMorgan Chase Bank ~~(4.25~~(3.25 percent at ~~September 30, 2017)~~March 31, 2020),

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

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(ii) LIBOR. ~~The credit facility’s~~

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 September 2017, we elected to enter into an Investment Grade Period under our credit facility, which had the effect of releasing all collateral formerly securing the credit facility. If the Investment Grade Period under the credit facility terminates (whether automatically or by our election), the credit facility will 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.

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.~~

Credit Facility.

Liquidity. Our principal source of liquidity is the available borrowing capacity under our ~~credit facility.~~ Credit Facility. At ~~September 30, 2017,~~March 31, 2020, our commitments from our bank group totaled $2.0 billion, all of which were ~~$2.0 billion.~~

unused.

Debt ratings.We receive debt credit ratings from S&P, Moody’s and Fitch Ratings ~~(“Fitch”), which~~and are ~~subject to regular reviews. In August 2017, our long-term debt was assigned a first-time~~designated as investment grade ~~rating by Fitch, and our rating by S&P was raised to an investment grade rating.~~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. ~~An explanation of the significance of each rating may be obtained from the applicable rating agency.~~

A downgrade in our credit ratings could (i) negatively impact our ~~costs~~cost of capital and our ability to effectively execute aspects of our strategy, (ii) affect our ability to raise debt in the public debt markets, and the cost of any new debt could be much higher than our outstanding debt and (iii) negatively affect our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. Further, if we are unable to maintain credit ratings of “Ba2” or better from Moody’s and “BB” or better from S&P, the ~~Investment Grade Period~~investment grade period under our Credit Facility will automatically terminate and cause ~~the credit facility~~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, 2017;~~occurred; however, we cannot be ~~assured~~certain that our credit ratings will not be downgraded in the future.

Book capitalization and current ~~ratio~~. ratio. Our net book capitalization at ~~September 30, 2017~~March 31, 2020 was ~~$11.3~~$12.2 billion, consisting of cash and cash equivalents of $165 million, debt of $~~2.7 billion~~$4.0 billion and stockholders’ equity of $~~8.6~~ $8.4 billion. Our net book capitalization at December 31, ~~2016~~2019 was ~~$10.2~~$21.8 billion, consisting ~~of $0.1 billion~~ of cash and cash equivalents of $70 million, debt of ~~$2.7~~$4.0 billion and stockholders’ equity of ~~$7.6~~$17.8 billion. Our ratio of net debt to net book capitalization was 2431 percent and 26 18 percent at ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016,~~2019, respectively. Our ratio of current assets to current liabilities was ~~0.66~~2.16 to 1.0 at ~~September 30, 2017~~March 31, 2020, as compared to ~~0.73~~0.89 to 1.0 at December 31, ~~2016.~~

~~Inflation and changes in prices.~~ ~~Our revenues, the value~~2019.

Table of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the nine months ended September 30, 2017, we received an average of $46.34~~per Bbl of oil and $2.96per Mcf of natural gas before consideration of commodity derivative contracts compared to $37.75per Bbl of oil and $1.97~~per Mcf of natural gas in the nine months ended September 30, 2016. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business.

Contents

Critical Accounting Policies, Practices and Estimates

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

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

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

There have been no material changes in our critical accounting policies and procedures during the ~~nine~~three months ended ~~September 30, 2017.~~March 31, 2020. 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, ~~2016,~~2019, filed with the ~~United States~~ Securities and Exchange Commission ~~(the “SEC”~~(“SEC”) on February ~~22, 2017.~~

19, 2020.

New accounting pronouncements issued but not yet adopted.In May 2014, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.

~~In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral~~ See Note 2 of the ~~Effective Date,~~Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” ~~which deferred the effective date~~for information regarding new accounting pronouncements issued but not yet adopted.

Table of ASU No. 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. We expect to use the modified retrospective method to adopt the standard, meaning the cumulative effect of initially applying the standard will be recognized with an adjustment to retained earnings on January 1, 2018. We have substantially completed our internal evaluation of the adoption of this standard, which included a review of all revenue-related contracts with customers and the application of the new revenue recognition model against those contracts. We are also updating our revenue recognition policy to conform to the new standard. We also expect to expand our revenue recognition related disclosure. Including those changes previously discussed, we do not expect this new guidance will have a material impact on our consolidated financial statements.

In February 2016, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for finance and operating leases. Lease expense recognition on the income statement will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018 and early adoption is permitted. We are evaluating the impact that this new guidance will have on our consolidated financial statements.

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

output. This new guidance is effective for annual periods beginning after December 15, 2017, and early adoption is allowed. We are evaluating the impact this new guidance will have on our consolidated financial statements.

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, ~~2016.~~

2019.

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, 2017~~,March 31, 2020, 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~~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 75 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~~. 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.~~our earnings. The following table sets forth the hypothetical impact on the fair value of the commodity price risk management arrangements from an average increase and decrease in the commodity price of $5.00 per Bbl of oil and $0.50 per MMBtu of natural gas from the commodity prices at ~~September 30, 2017:~~

Increase of

Decrease of

$5.00 per Bbl and

$5.00 per Bbl and
(in millions)

$0.50 per MMBtu

$0.50 per MMBtu

Gain (loss):

Oil derivatives
$
(289)

$
289

Natural gas derivatives

(31)

31

Total
$
(320)

$
320

March 31, 2020:


(in millions)	Increase of $5.00 per Bbl and $0.50 per MMBtu		Decrease of $5.00 per Bbl and $0.50 per MMBtu
Gain (loss):
Oil derivatives	$	(341)	$	341
Natural gas derivatives	(98)		98
Total	$	(439)	$	439

At ~~September 30, 2017,~~March 31, 2020, we had (i) oil price swaps ~~that settle on a monthly basis~~ covering future oil production from ~~October~~April 1, ~~2017~~2020 through December 31, ~~2019~~2021 and (ii) oil basis swaps covering our Midland to Cushing basis differential from ~~October~~April 1, ~~2017~~2020 to December 31, ~~2019.~~2021. The ~~average~~ NYMEX oil price ~~for the~~ ~~nine~~ ~~months ended September 30, 2017~~at March 31, 2020 was ~~$49.45~~$20.48 per Bbl. At ~~October 30, 2017~~,April 27, 2020, the NYMEX oil price was ~~$54.15~~$12.78 per Bbl.

At ~~September 30, 2017~~,March 31, 2020, we had (i) natural gas price swaps that settle on a monthly basis covering future natural gas production from ~~October~~April 1,, ~~2017~~ 2020 to December 31, ~~2019~~.2022 and (ii) natural gas basis swaps covering our El Paso Permian to Henry Hub and WAHA to Henry Hub basis differentials from April 1, 2020 to December 31, 2022. The ~~average~~ NYMEX natural gas price ~~for the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2017~~at March 31, 2020 was ~~$3.06~~ $1.64 per MMBtu. At ~~October 30, 2017~~,April 27, 2020, the NYMEX natural gas price was ~~$2.97~~$1.82 per MMBtu.

~~A decrease~~

An increase in the average forward NYMEX oil and natural gas prices ~~below~~above those at ~~September 30, 2017~~March 31, 2020 would decrease the fair value ~~liability~~asset of our commodity derivative contracts from their recorded balance at ~~September 30, 2017~~.March 31, 2020. 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~~asset would be recorded in earnings as a ~~gain.~~loss. However, ~~an increase~~a decrease in the average forward NYMEX oil and natural gas prices ~~above~~below those at ~~September 30, 2017~~March 31, 2020 would increase the fair value ~~liability~~asset of our commodity derivative contracts from their recorded balance at ~~September 30, 2017~~.March 31, 2020. The potential increase in our fair value ~~liability~~asset would be recorded in earnings as a ~~loss.~~gain. 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.

Table of Contents

We recorded a gain of approximately $1.8 billion and a loss of approximately $1.1 billion on derivatives for the three months ended March 31, 2020 and 2019, respectively. The change between the periods 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, 2017~~.March 31, 2020. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the ~~nine~~three months ended ~~September 30, 2017~~:

March 31, 2020:

~~Commodity Derivative~~

~~Instruments~~

(in millions)

Commodity Derivative Instruments
Net Assets (Liabilities) ~~(a)~~

Fair value of contracts outstanding at December 31, ~~2016~~

2019

(102)

~~(174)~~

Changes in fair values ~~(b)~~

(a)

1,769

~~289~~

Contract maturities

(201)

~~(126)~~

Fair value of contracts outstanding at ~~September 30, 2017~~

March 31, 2020 (b)

1,466

~~(11)~~

(a)

~~Represents the fair values of open derivative contracts subject to market risk.~~

~~(b)~~

At inception, new derivative contracts entered into by us have no intrinsic value.

(b) Represents the fair value of open derivative contracts subject to market risk.

See Note 75 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~~.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 had no outstanding interest rate derivative contracts at March 31, 2020. We are exposed to changes in interest rates as a result of our ~~credit facility,~~Credit Facility, and the terms of our ~~credit facility~~Credit Facility require us to pay higher interest rate margins as our credit ratings decrease.

We had ~~total~~no indebtedness ~~of $368~~ ~~million~~ outstanding under our ~~credit facility~~Credit Facility at ~~September 30, 2017. The impact~~March 31, 2020.

Table of ~~a one percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $~~4 ~~million.~~

Contents

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and ~~Procedures~~. 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, 2017~~March 31, 2020 at the reasonable assurance level.

Changes in Internal Control over Financial ~~Reporting~~. 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.

Table of Contents

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the information set forth in this Quarterly Report, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2016, under the headings “Item 1. Business — Competition,” “— Marketing Arrangements” and “— Applicable Laws and Regulations,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” which risks could materially affect our business, financial condition or future results.

There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, ~~2016,~~2019, other than ~~updating~~as set forth below.

The COVID-19 pandemic has adversely affected our business, and the ~~risk factor below. The risks described in our Annual Report~~ultimate effect on Form 10-K for the year ended December 31, 2016 and in this Quarterly Report 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 updated risk factor is as follows:~~

~~Future price declines could result in a reduction in the carrying value of our proved oil and natural gas properties, which could adversely affect our results of operations.~~

Declines in commodity prices may result in us having to make substantial downward adjustments to the value of our estimated proved reserves. If this occurs, or if our estimates of production or economic factors change, accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our proved oil and natural gas properties for impairments. We are required to perform impairment tests on proved assets whenever events or changes in circumstances warrant a review of our proved oil and natural gas properties. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our oil and natural gas properties, the carrying value may not be recoverable and therefore require a write-down. The primary factors that may affect management’s estimates of future cash flows are (i) commodity futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve volume adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) results of future drilling activities and (v) prevailing market rates of income and expenses from integrated assets. We may incur impairment charges in the future, which could materially adversely affect ourposition, results of operations ~~in the period incurred.~~

~~Based on economic factors at September 30, 2017, we determined that undiscounted future~~and/or cash flows ~~attributable~~will depend on future developments, which are highly uncertain and cannot be predicted.

In December 2019, COVID-19 was reported to ~~our NBBS field with a net book value~~have surfaced in China. The global spread of ~~approximately $1.1 billion indicated that its carrying amount was expected~~this virus has caused business disruptions around the world beginning in January 2020, including disruption to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows) subsequent to September 30, 2017. We estimate that if the oil and natural gas industry. In March 2020, the World Health Organization declared the outbreak of COVID-19 to be a pandemic, and the U.S. economy began to experience pronounced effects. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains and created significant volatility and disruption of financial and commodity markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. As a result, there has been a significant reduction in demand for and prices ~~used~~of oil and natural gas. The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the ~~estimated fair value analysis would have been approximately 10 percent lower at September 30, 2017 with no other changes~~expected time frame, is uncertain and depends on various factors, including how the pandemic and measures taken in ~~capital costs, operating costs, price differentials, or reserve performance curves, we could have recognized a non-cash impairment in that period of approximately $470 million related~~response to ~~our NBBS field. 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~~it impact demand for oil and natural gas, ~~prices. However, we are unable~~the availability of personnel, equipment and services critical to ~~estimate~~our ability to operate our properties and the ~~correlation between these assumptions~~impact of potential governmental restrictions on travel, transports and ~~any estimated commodity price change,~~operations. There is uncertainty around the extent and ~~these and other assumptions may worsen or partially mitigate some~~duration of the ~~effects~~disruption, including any resurgence. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the U.S. and world economies, the U.S. capital markets and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. The disruption from the current pandemic has had a ~~reduction in commodity prices, including~~material adverse impact on our industry and thus our results and outlook, but the ~~ultimate~~degree of the adverse financial impact ~~and amount~~on us cannot be reasonably estimated at this time.

Table 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 cause us to recognize an impairment charge in a particular field or the magnitude of any such impairment charge.

Contents

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

Period

Total number of shares withheld (a)

Average price per share

Total number of shares purchased as part of publicly announced plans

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

July 1, 2017 - July 31, 2017

585

$
121.87

-

August 1, 2017 - August 31, 2017

5,103

$
116.37

-

September 1, 2017 - September 30, 2017

213

$
123.73

-




(a)
Represents shares that were withheld by us to satisfy tax withholding obligations of certain of our officers and key employees that arose upon the lapse of restrictions on restricted stock.




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


Period	Total number of shares purchased (a)	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs (b)	Approximate dollar value of shares that may yet be purchased under the plans or programs (b) (in billions)
January 1, 2020 - January 31, 2020	1,174,796	$	88.77	1,125,906	$	1.15
February 1, 2020 - February 29, 2020	1,301	$	77.03	—	$	1.15
March 1, 2020 - March 31, 2020	465	$	41.85	—	$	1.15

(a) Includes 50,656 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 during the first quarter of 2020.
(b) During the first quarter of 2020, we repurchased and retired 1,125,906 common shares for $100 million under our $1.5 billion share repurchase program that was publicly announced in September 2019. The program does not have a stated expiration date.

Table of Contents

Item 6. Exhibits

Exhibit

~~Number~~

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

~~Third~~Fourth Amended and Restated Bylaws of Concho Resources Inc., as amended ~~March 27, 2017~~January 2, 2018 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on ~~March 28, 2017,~~January 4, 2018, and incorporated herein by reference).

~~4.1~~10.1

~~Specimen Common Stock Certificate~~Form of Performance Unit Award Agreement, dated January 2, 2020 (filed as Exhibit ~~4.1 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).~~

~~4.2~~

Twelfth Supplemental Indenture, dated September 26, 2017, among Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.110.1 to the Company’s Current Report on Form 8-K on ~~September 26, 2017,~~January 6, 2020, and incorporated herein by reference).

~~4.3~~

~~Thirteenth Supplemental Indenture, dated September 26, 2017, among~~

22.1

(a)

Guarantor subsidiaries of Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on September 26, 2017, and incorporated herein by reference).

~~4.4~~

~~Form of 3.750% Senior Notes due 2027 (included in Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on September 26, 2017, and incorporated herein by reference).~~

~~4.5~~31.1

(a)

~~Form of 4.875% Senior Notes due 2047 (included in Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on September 26, 2017, and incorporated herein by reference).~~

~~31.1~~

~~(a)~~

Certification of Chief Executive Officer pursuant to ~~Section 302 of~~Rule 13a-14(a) under the ~~Sarbanes-Oxley~~Securities Exchange Act of ~~2002.~~

1934.

31.2

(a)

Certification of Chief Financial Officer pursuant to ~~Section 302 of~~Rule 13a-14(a) under the ~~Sarbanes-Oxley~~Securities Exchange Act of ~~2002.~~

1934.

32.1

(b)

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section ~~906 of the Sarbanes-Oxley Act of 2002.~~

1350.

32.2

(b)

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section ~~906 of the Sarbanes-Oxley Act of 2002.~~

1350.

101.INS

(a)

XBRL Instance ~~Document.~~

Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH

(a)

Inline XBRL Schema Document.

101.CAL

(a)

Inline XBRL Calculation Linkbase Document.

101.DEF

(a)

Inline XBRL Definition Linkbase Document.

101.LAB

(a)

Inline XBRL Labels Linkbase Document.

101.PRE

(a)

Inline XBRL Presentation Linkbase Document.

104

(a)

The cover page of Concho Resources Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020, formatted in Inline XBRL and included within the Exhibit 101 attachments.

(a) Filed herewith.
(b) Furnished herewith.

~~(a) Filed herewith.~~

~~(b) Furnished herewith.~~

Table of Contents

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:

~~November~~May 1, ~~2017~~

2020

/s/ Timothy A. Leach

Timothy A. Leach

Chairman of the Board of Directors and Chief ~~Executive~~

Executive Officer

(Principal Executive Officer)

~~/s/ Jack F. Harper~~

~~Jack F. Harper~~

~~President and Chief Financial Officer~~

~~(Principal Financial Officer)~~

/s/ Brenda R. Schroer

Brenda R. Schroer

Senior Vice President, Chief ~~Accounting~~Financial Officer and ~~Treasurer~~

Treasurer

(Principal Financial Officer)

/s/ Jacob P. Gobar

Jacob P. Gobar

Vice President and Chief Accounting Officer

(Principal Accounting Officer)


PART I – FINANCIAL INFORMATION:		~~iii~~	iv

	Item 1. Consolidated Financial Statements (Unaudited)	~~iii~~ iv

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	32 22

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	57 36

	Item 4. Controls and Procedures	59 38

PART II – OTHER INFORMATION:		60	39

	Item 1. Legal Proceedings	60 39

	Item 1A. Risk Factors	60 39

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	61 40

	Item 6. Exhibits	62 41


Consolidated Balance Sheets at ~~September 30, 2017~~March 3 1 , 20 20 and December 31, ~~2016~~201 9			1

Consolidated Statements of Operations for the Three ~~and Nine~~ Months Ended ~~September 30, 2017~~March 3 1 , 20 20 and ~~2016~~ 2019			2

Consolidated ~~Statement~~Statements of Stockholders’ Equity for the ~~Nine~~ Three Months Ended ~~September 30, 2017~~ March 3 1 , 20 20 and 2019			3

Consolidated Statements of Cash Flows for the ~~Nine~~Three Months Ended ~~September 30, 2017~~March 3 1 , 20 20 and ~~2016~~ 2019			4

Condensed Notes to Consolidated Financial Statements			5


					September 30,		December 31,
(in millions, except share and per share amounts)					2017		2016
Assets
Current assets:
	Cash and cash equivalents			$	-	$	53
	Accounts receivable, net of allowance for doubtful accounts:
		Oil and natural gas			271		220
		Joint operations and other			223		238
	Derivative instruments				4		4
	Prepaid costs and other				37		31
			Total current assets		535		546
Property and equipment:
	Oil and natural gas properties, successful efforts method				20,754		18,476
	Accumulated depletion and depreciation				(8,167)		(7,390)
		Total oil and natural gas properties, net			12,587		11,086
	Other property and equipment, net				232		216
		Total property and equipment, net			12,819		11,302
Funds held in escrow					-		43
Deferred loan costs, net					14		11
Intangible asset - operating rights, net					24		24
Inventory					15		16
Noncurrent derivative instruments					28		-
Other assets					47		177
	Total assets			$	13,482	$	12,119
Liabilities and Stockholders’ Equity
Current liabilities:
	Accounts payable - trade			$	36	$	28
	Bank overdrafts				68		-
	Revenue payable				135		132
	Accrued drilling costs				381		359
	Derivative instruments				37		82
	Other current liabilities				153		152
			Total current liabilities		810		753
Long-term debt					2,738		2,741
Deferred income taxes					1,150		766
Noncurrent derivative instruments					6		96
Asset retirement obligations and other long-term liabilities					147		140
Commitments and contingencies (Note 9)
Stockholders’ equity:
	Common stock, $0.001 par value; 300,000,000 authorized; 149,297,932 and
		146,488,685 shares issued at September 30, 2017 and December 31, 2016, respectively			-		-
	Additional paid-in capital				7,125		6,783
	Retained earnings				1,573		884
	Treasury stock, at cost; 597,551 and 429,708 shares at September 30, 2017 and
		December 31, 2016, respectively			(67)		(44)
			Total stockholders’ equity		8,631		7,623
	Total liabilities and stockholders’ equity			$	13,482	$	12,119

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


		Common Stock				Additional							Total
		Issued				Paid-in		Retained	Treasury Stock			Stockholders’
(in millions, except share data)		Shares		Amount		Capital		Earnings	Shares		Amount		Equity
		(in thousands)							(in thousands)
BALANCE AT DECEMBER 31, 2016		146,489	$	-	$	6,783	$	884	430	$	(44)	$	7,623
	Adoption of ASU No. 2016-09 (Note 2)	-		-		8		-	-		-		8
BALANCE AT JANUARY 1, 2017		146,489		-		6,791		884	430		(44)		7,631
	Net income	-		-		-		689	-		-		689
	Common stock issued in business combinations	2,177		-		291		-	-		-		291
	Stock options exercised	20		-		-		-	-		-		-
	Grants of restricted stock	445		-		-		-	-		-		-
	Performance unit share conversion	249		-		-		-	-		-		-
	Cancellation of restricted stock	(82)		-		-		-	-		-		-
	Stock-based compensation	-		-		43		-	-		-		43
	Purchase of treasury stock	-		-		-		-	168		(23)		(23)
BALANCE AT SEPTEMBER 30, 2017		149,298	$	-	$	7,125	$	1,573	598	$	(67)	$	8,631

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


			September 30,		December 31,
(in millions, except number of projects)			2017		2016

Capitalized exploratory well costs that have been capitalized for a period of one year or less		$	266	$	141
Capitalized exploratory well costs that have been capitalized for a period greater than one year			4		10
	Total capitalized exploratory well costs	$	270	$	151
Number of projects with exploratory well costs that have been capitalized for a period greater
	than one year		4		8


		Restricted		Stock		Performance
		Stock Shares		Options		Units

Outstanding at December 31, 2016			1,157,270		20,000		331,526
	Awards granted (a)		445,384		-		108,398
	Options exercised		-		(20,000)		-
	Awards cancelled / forfeited		(82,200)		-		(43,333)
	Lapse of restrictions		(389,965)		-		-
Outstanding at September 30, 2017		1,130,489		-		396,591

(a) Weighted average grant date fair value per share/unit		$	121.77	$	-	$	183.48


September 30, 2017
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable				Consolidated		Consolidated
				Assets				Inputs		Inputs		Total		Balance		Balance
(in millions)				(Level 1)				(Level 2)		(Level 3)		Fair Value		Sheet		Sheet

	Assets:
		Current:
			Commodity derivatives		$	-	$	35	$	-	$	35	$	(31)	$	4
		Noncurrent:
			Commodity derivatives			-		44		-		44		(16)		28

	Liabilities:
		Current:
			Commodity derivatives			-		(68)		-		(68)		31		(37)
		Noncurrent:
			Commodity derivatives			-		(22)		-		(22)		16		(6)

	Net derivative instruments				$	-	$	(11)	$	-	$	(11)	$	-	$	(11)


				Estimated
		Carrying		Fair Value		Impairment
(in millions)		Amount		(Level 3)		Expense

March 2016	$	3,438	$	1,913	$	1,525


				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Price Swaps: (a)
	*2017:*
		Volume (Bbl)								9,370,080		9,370,080
		Price per Bbl							$	51.33	$	51.33
	*2018:*
		Volume (Bbl)		8,180,629		7,546,170		7,064,318		6,676,007		29,467,124
		Price per Bbl	$	51.54	$	51.45	$	51.36	$	51.26	$	51.41
	*2019:*
		Volume (Bbl)		5,314,000		5,090,000		4,897,000		4,721,000		20,022,000
		Price per Bbl	$	52.54	$	52.52	$	52.54	$	52.55	$	52.54
Oil Basis Swaps: (b)
	*2017:*
		Volume (Bbl)								8,508,000		8,508,000
		Price per Bbl							$	(0.74)	$	(0.74)
	*2018:*
		Volume (Bbl)		7,936,000		7,521,000		6,961,000		6,684,000		29,102,000
		Price per Bbl	$	(1.02)	$	(1.01)	$	(1.01)	$	(1.01)	$	(1.01)
	*2019:*
		Volume (Bbl)		4,581,000		4,428,000		4,262,000		4,139,000		17,410,000
		Price per Bbl	$	(1.17)	$	(1.17)	$	(1.18)	$	(1.18)	$	(1.17)
Natural Gas Price Swaps: (c)
	*2017:*
		Volume (MMBtu)								14,673,000		14,673,000
		Price per MMBtu							$	3.10	$	3.10
	*2018:*
		Volume (MMBtu)		11,156,000		10,641,000		10,219,000		9,904,000		41,920,000
		Price per MMBtu	$	3.06	$	3.05	$	3.05	$	3.04	$	3.05
	*2019:*
		Volume (MMBtu)		2,791,533		2,681,387		2,578,537		2,489,535		10,540,992
		Price per MMBtu	$	2.86	$	2.85	$	2.85	$	2.85	$	2.85


(a) The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price.
(b) The basis differential price is between Midland – WTI and Cushing – WTI.
(c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.


(in millions)			Tender Offer		Extinguishment		Total

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


Condensed Consolidating Balance Sheet
September 30, 2017


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

ASSETS
Accounts receivable - related parties		$	8,903	$	(653)	$	-	$	(8,250)	$	-
Other current assets			14		515		6		-		535
Oil and natural gas properties, net			-		11,968		619		-		12,587
Property and equipment, net			-		232		-		-		232
Investment in subsidiaries			2,963		-		-		(2,963)		-
Other long-term assets			42		86		-		-		128
	Total assets	$	11,922	$	12,148	$	625	$	(11,213)	$	13,482

LIABILITIES AND EQUITY
Accounts payable - related parties		$	(653)	$	8,290	$	613	$	(8,250)	$	-
Other current liabilities			50		756		4		-		810
Long-term debt			2,738		-		-		-		2,738
Other long-term liabilities			1,156		141		6		-		1,303
Equity			8,631		2,961		2		(2,963)		8,631
	Total liabilities and equity	$	11,922	$	12,148	$	625	$	(11,213)	$	13,482


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
Three Months Ended September 30, 2016


			Parent		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Entries		Total

Total operating revenues		$	-	$	430	$	-	$	430
Total operating costs and expenses			41		(469)		-		(428)
	Income (loss) from operations		41		(39)		-		2
Interest expense			(52)		(1)		-		(53)
Loss on extinguishment of debt			(28)		-		-		(28)
Other, net			(42)		(2)		42		(2)
	Loss before income taxes		(81)		(42)		42		(81)
Income tax benefit			30		-		-		30
	Net loss	$	(51)	$	(42)	$	42	$	(51)


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		(835)		(6)		-		(553)
	Income from operations		288		963		2		-		1,253
Interest expense			(117)		(1)		-		-		(118)
Loss on extinguishment of debt			(66)		-		-		-		(66)
Other, net			982		18		-		(982)		18
	Income before income taxes		1,087		980		2		(982)		1,087
Income tax expense			(398)		-		-		-		(398)
	Net income	$	689	$	980	$	2	$	(982)	$	689

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2016


			Parent		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Entries		Total

Total operating revenues		$	-	$	1,110	$	-	$	1,110
Total operating costs and expenses			(177)		(2,853)		-		(3,030)
	Loss from operations		(177)		(1,743)		-		(1,920)
Interest expense			(159)		(3)		-		(162)
Loss on extinguishment of debt			(28)		-		-		(28)
Other, net			(1,755)		(10)		1,756		(9)
	Loss before income taxes		(2,119)		(1,756)		1,756		(2,119)
Income tax benefit			782		-		-		782
	Net loss	$	(1,337)	$	(1,756)	$	1,756	$	(1,337)


			Three Months Ended September 30,
			2017				2016
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Lease operating expenses		$	100	$	5.68	$	66	$	4.63
Workover costs			6		0.31		5		0.35
	Total oil and natural gas production expenses	$	106	$	5.99	$	71	$	4.98


		Nine Months Ended September 30,
		2017				2016
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Lease operating expenses		$	278	$	5.47	$	225	$	5.62
Workover costs			15		0.29		15		0.38
	Total oil and natural gas production expenses	$	293	$	5.76	$	240	$	6.00


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

Gain (loss):
	Oil derivatives		$	(289)	$	289
	Natural gas derivatives			(31)		31
		Total	$	(320)	$	320


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, 2017 - July 31, 2017		585	$	121.87	-
August 1, 2017 - August 31, 2017		5,103	$	116.37	-
September 1, 2017 - September 30, 2017		213	$	123.73	-


(a)	Represents shares that were withheld by us to satisfy tax withholding obligations of certain of our officers and key employees that arose upon the lapse of restrictions on restricted stock.