GLOSSARY OF TERMS

Item 1A. Risk Factors

Item 6. Selected Financial Data

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Item 8. Financial Statements and Supplementary Data

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Item 10.Directors, Executive Officers and Corporate Governance

Item 11.Executive Compensation

Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13.Certain Relationships and Related Transactions, and Director Independence

Item 14.Principal Accounting Fees and Services

Item 16. Form 10-K Summary

locations.

Drilling Activities

Our Production, Prices and Expenses

Marketing Arrangements

firm sales agreements for both oil and natural gas include delivery commitments. We believe our current production and reserves are sufficient to fulfill these delivery commitments. See Note 11 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information.

Non-GAAP Financial Measures and Reconciliations

Based on SEC pricing as of December 31, 2019, estimated future development costs required for the development of proved undeveloped reserves are projected to be approximately $2.4 billion over the next five years.

Drilling Activities

Data.”

Critical Accounting Policies, Practicesand Practices

New accounting pronouncements issued but not yet adopted

the valuation estimate was finalized.

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the fiscal year ended December 31, ~~2017~~

2019

☐

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

For the transition period from ______________________ to

______________________

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)


~~Delaware~~		~~76-0818600~~
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)

			~~(432) 683-7443~~

	(432)	683-7443
(Registrant’s telephone number, including area code)
			Securities Registered Pursuant to Section 12(b) of the Act:

Securities Registered Pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes☑ þNo o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o ¨No☑

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☑ þNo 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☑ þNo o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☑

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 filero	☐

Non-accelerated filero ~~(Do not check if a smaller reporting company)~~	☐	Smaller reporting companyo	☐

Emerging growth companyo	☐

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☑

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter:

$
17,883,517,337

Number of shares of the registrant’s common stock outstanding as of February 16, 2018:

149,067,852

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $ 20,479,372,863

Number of shares of the registrant's common stock outstanding as of February 14, 2020 196,705,121

Documents Incorporated by ~~Reference:~~

Reference

Portions of the registrant’s definitive proxy statement for its ~~2018~~2020 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, ~~2017,~~2019, are incorporated by reference into Part III of this Form 10-K for the year ended December 31, ~~2017.~~

2019.

TABLE OF CONTENTS



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	1

PART I	2
Item 1. Business	2
General	2
Business and Properties	2
Summary of ~~Core~~ Operating Areas	3 2
Drilling Activities	5 3
Our Production, Prices and Expenses	6 4
Productive Wells	7 5
Marketing Arrangements	8 5
Delivery Commitments	6
Our Principal Customers	8 6
Competition	8 6
Working Capital	9 6
Applicable Laws and Regulations	10 7
Our Employees	14 11
Available Information	15 11
Non-GAAP Financial Measures and Reconciliations	16 11
Item 1A. Risk Factors	18 13
Risks Related to Our Business	18 13
Risks Related to Our Common Stock	34 30
Item 1B. Unresolved Staff Comments	34 30
Item 2. Properties	34 31
Our Oil and Natural Gas Reserves	34 31
Developed and Undeveloped Acreage	38 34
Title to Our Properties	40 34
Item 3. Legal Proceedings	40 35
Item 4. Mine Safety Disclosures	40 35

PART II	41 36
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	41 36
Market Information	41 36
~~Dividend Policy~~	41
Repurchases of Equity Securities	41 36
Item 6. Selected Financial Data	42 36
Selected Historical Financial Information	42 37
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	45 38
Overview	45 38
Financial and Operating Performance	46 39
Commodity Prices	47 40
Recent Events	48 41
Derivative Financial Instruments	49 41
Results of Operations	50 42
~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~	52
~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~	59
Capital Commitments, Capital Resources and Liquidity	65 50
Critical Accounting Policies and Practices	70 54
Recent Accounting Pronouncements	74 58
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	75 59
Credit risk	75 59

Table of Contents



Commodity price risk	75 59
Interest rate risk	76 60
Item 8. Financial Statements and Supplementary Data	77 61

Glossary of Terms	64
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	77 114
Item 9A. Controls and Procedures	77 114
Evaluation of Disclosure Controls and Procedures	77 114
~~Changes in Internal Control over Financial Reporting~~	77
Management’s Report on Internal Control over Financial Reporting	77 114
Changes in Internal Control over Financial Reporting	115
Report of Independent Registered Public Accounting Firm	78 115
Item 9B. Other Information	79 116

PART III	80 117
Item 10. Directors, Executive Officers and Corporate Governance	80 117
Code of Ethics	80 117
Item 11. Executive Compensation	80 117
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	80 117
Equity Compensation Plans	80 117
Item 13. Certain Relationships and Related Transactions, and Director Independence	81 117
Item 14. Principal ~~Accounting~~Accountant Fees and Services	81 117

PART IV	82 118
Item 15. Exhibits, Financial Statement Schedules	82 118
Item 16. Form 10-K Summary	85 121

SIGNATURES	86
~~GLOSSARY OF TERMS~~122	88
~~INDEX TO CONSOLIDATED FINANCIAL STATEMENTS~~	~~F-1~~

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, 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 “Item 1A. Risk Factors” in this report, as well as those factors summarized below:

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 of~~differential between index oil ~~and~~or natural gas ~~reserves;~~

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

·~~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;~~

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

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

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

·~~risks associated with acquisitions, including liabilities associated with acquired properties or businesses and the ability to realize expected benefits;~~

·prices received;

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

competition in the oil and natural gas industry;

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

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

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

·gas reserves;

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

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

·~~difficult and adverse conditions~~operations in the ~~domestic~~Permian Basin of West Texas and ~~global capital and credit markets;~~

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

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

·Southeast New Mexico;

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

uncertainty concerning our assumed or possible future results of operations;

evolving cybersecurity risks, such as those involving unauthorized access 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;

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

general economic and business conditions, either internationally or domestically;

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

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

risks related to ongoing expansion of our business, including 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;

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

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

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

the impact of potential changes in our credit ratings; and

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

·~~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.~~

reserves.

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

PART I

Item 1.~~Busines~~Business

General

Concho Resources Inc., a Delaware corporation (“Concho,” the “Company,” “we,” “us” and “our”) ~~formed~~incorporated in February 2006, is an independent oil and natural gas company engaged in the acquisition, development, exploration and production of oil and natural gas properties. Our ~~core~~ operations are primarily focused in the Permian Basin of ~~southeast~~West Texas and Southeast New ~~Mexico and west Texas.~~Mexico. The Permian Basin is one of the most prolific oil and natural gas producing regions in the United States and is characterized by an extensive production history, long reserve life, multiple producing horizons and ~~enhanced~~significant recovery potential. ~~Currently, the majority of the rigs running in the Permian Basin are drilling horizontal wells.~~ Concho’s legacy in the Permian Basin provides us a deep understanding of operating and geological ~~trends. We~~trends, and we are actively developing our resource base by utilizing ~~extended length lateral drilling, enhanced completion techniques,~~long-lateral wells and multi-well pad locations and large-scale development projects throughout our four core operating areas: the Northern Delaware Basin, the Southern Delaware Basin, the Midland Basin and the New Mexico Shelf. Our strategy remains focused on development and exploration activities on our multi-year project inventory and pursuing acquisitions that meet our strategic and financial objectives.

Business and Properties

Our ~~core~~ operations are focused in the Permian Basin, which underlies an area of ~~southeast~~West Texas and Southeast New Mexico ~~and west Texas~~ approximately 250 miles wide and 300 miles long. Commercial accumulations of hydrocarbons occur in multiple stratigraphic horizons, at depths ranging from less than 1,000 feet to over 25,000 feet. At December 31, ~~2017, substantially all of~~2019, our ~~840~~1,002 MMBoe total estimated proved reserves were ~~located in our core operating areas and~~approximately 74 percent proved developed, as compared to proved developed reserves of approximately 69 percent of total estimated proved reserves of 1,187 MMBoe at December 31, 2018. Our total estimated proved reserves at December 31, 2019 consisted of approximately 6062 percent oil and 4038 percent natural gas.

We have ~~assembled a multi-year inventory~~one operating segment and one reporting unit, which is oil and natural gas development, exploration and production. All of ~~horizontal~~our operations are conducted in one geographic area of the United States.

On July 19, 2018, we completed the acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”). RSP was an independent oil and natural gas company engaged in the acquisition, exploration, development and ~~exploration projects across~~production of oil and natural gas reserves in the Permian Basin. The vast majority of RSP’s acreage was located on large, contiguous acreage blocks in the core of the Midland Basin and the Delaware Basin. The acquisition added approximately 92,000 net acres to our ~~four core operating areas.~~

asset portfolio.

The following table ~~sets forth information with respect to~~summarizes our drilling ~~of wells commenced~~activity during the periods indicated:

Years Ended December 31,

2017

2016

2015

Gross wells

311

249

361
Net wells

197

170

228

Percent of gross wells drilled horizontally

100%

100%

86%

Percent of gross wells:

Producers

61%

56%

74%

Unsuccessful

1%

-

1%

Awaiting completion at year-end

38%

44%

25%

100%

100%

100%



	Years Ended December 31,
	2019		2018		2017
Gross wells	454		428		311
Net wells	257		266		197

Percent of gross wells drilled horizontally	100	%	100	%	100	%

Percent of gross wells:
Productive	55	%	44	%	61	%
Unsuccessful	—	%	—	%	1	%
Awaiting completion at year end	45	%	56	%	38	%
	100	%	100	%	100	%

Summary of ~~Core~~ Operating Areas

The following is a summary of information regarding our ~~core~~ operating areas:

December 31, 2017

Estimated

Total

Total

2017 Average

Proved

Gross

Net

Daily

Reserves

% Proved

Acreage

Acreage

Production
Core Operating Areas

(MMBoe)

% Oil

Developed

(in thousands)

(in thousands)

(MBoe per Day)

Northern Delaware Basin

295

50%

68%

373

259

90
Southern Delaware Basin

127

72%

62%

146

94

27
Midland Basin

266

66%

67%

265

154

45
New Mexico Shelf

152

56%

87%

121

78

31

Total

840

60%

70%

905

585

193

~~Core operating~~

Operating Areas December 31, 2019

Estimated
Proved
Reserves
(MMBoe)
% Oil
% Proved
Developed

Total
Gross
Acreage
(in thousands)

Total
Net
Acreage
(in thousands)

2019 Average
Daily
Production
(MBoe per Day)
Delaware Basin 556 61 % 76 % 524 352 217
Midland Basin 446 63 % 73 % 285 197 114
Total 1,002 62 % 74 % 809 549 331

Operating areas

~~Northern~~

Our operations are focused in the Delaware Basin and the Midland Basin, within the greater Permian Basin. Our development in both areas includes large-scale, full-field development to maximize resource recovery and program economics while optimizing well spacing, landing intervals, lateral length and completion techniques.

Delaware Basin.At December 31, ~~2017~~,2019, we had estimated proved reserves in this area of ~~295~~556 MMBoe, representing 3555 percent of our total proved reserves.

The Northern Delaware Basin is characterized by a thick, resource-rich hydrocarbon column that lends itself to multi-zone development. We leverage leading-edge horizontal drilling and completion technologies, utilizing multi-well pad sites to develop multiple producing formations. Our activity has targeted the Avalon shale and Bone Spring and Wolfcamp formations at depths from 6,500 to 13,500 feet. We continue to test and develop additional landing intervals within these formations.

During the year ended December 31, ~~2017~~,2019, we commenced drilling or participated in the drilling of ~~149 (78~~299 (148 net) wells in this ~~area. Throughout 2017,~~area, and we completed ~~126 (66~~294 (176 net) wells that are producing. ~~Additionally~~

Our activity in ~~2017, we abandoned 1 (1 net) well that~~2019 was ~~spud in 2014~~centered mostly on continued development of our assets, with an emphasis on multi-well pad sites and ~~used~~extended lateral lengths to ~~monitor offsetting well stimulations.~~ ~~During~~ ~~2017, we continued (i) development and step-out activity targeting~~develop multiple producing formations. We primarily target the Avalon, ~~shale,~~ Bone Spring ~~sands~~ and Wolfcamp ~~formation and (ii)~~formations, which generally range from 6,500 feet to ~~refine our completion techniques.~~ ~~During 2017, all of the wells we commenced or participated in drilling were drilled horizontally.~~

~~Southern Delaware~~13,500 feet.

Midland Basin.At December 31, ~~2017~~,2019, we had estimated proved reserves in this area of ~~128~~446 MMBoe, representing 1545 percent of our total proved reserves.

Across our Southern Delaware Basin acreage position, we primarily target the Bone Spring and Wolfcamp formations, which generally range from 8,000 to 12,500 feet in depth. We leverage leading-edge horizontal drilling and completion technologies, utilizing multi-well pad sites and extended lateral lengths, to develop these producing formations.

During the year ended December 31, ~~2017~~,2019, we commenced drilling or participated in the drilling of ~~61 (38~~155 (109 net) wells in this ~~area. Throughout 2017,~~area, and we completed ~~53 (33 net) wells~~ ~~that are producing. Additionally in 2017, we spud 2 (2~~185 (131 net) wells that ~~were subsequently abandoned due to mechanical issues.~~ ~~During~~ ~~2017, we continued (i) development and step-out activity~~

are producing.

~~targeting the Bone Spring sands and Wolfcamp shale and (ii) evaluation of our enhanced stimulation procedures of certain horizontal wells.~~ ~~During 2017, all of the wells we commenced or participated in drilling were drilled horizontally.~~

~~Midland Basin.~~ ~~At December 31, 2017, we had estimated proved reserves in this area of~~ ~~266~~ ~~MMBoe, representing~~ 32 ~~percent of our total proved reserves.~~

Our primary objectives in the Midland Basin area are the Spraberry and Wolfcamp formations, which ~~are typically encountered at depths of~~generally range from 7,500 feet to 11,500 feet. ~~On our Midland Basin assets, we~~We are developing these formations with horizontal drilling, utilizing multi-well pad sites and extended lateral development. ~~We are also continuing to optimize well spacing, landing intervals and completion techniques.~~

~~During~~ ~~the year ended December 31,~~ ~~2017, we commenced drilling or participated in the drilling of 58 (47 net) wells in this area.~~ ~~Throughout 2017, we completed 78 (49 net) wells~~ that are producing. Additionally in 2017, we spud 1 (1 net) well that was subsequently abandoned due to mechanical issues. During 2017, all of the wells we commenced or participated in drilling were drilled horizontally.

~~New Mexico Shelf.~~ ~~At December 31, 2017, we had estimated proved reserves in this area of 151 MMBoe, representing 18 percent of our total proved reserves.~~

Within this area our primary objectives are the Yeso, San Andres and Grayburg formations, with producing depths ranging from approximately 900 feet to 7,500 feet. During 2017, we continued our horizontal drilling of the Yeso formation.

~~During the year ended December 31, 2017, we commenced drilling or participated in the drilling of 43 (34 net) wells in this area.~~ ~~Throughout 2017, we completed 48 (39 net) wells~~ ~~that are producing. During 2017, all of the wells we commenced or participated in drilling were drilled horizontally.~~

The following table sets forth information with respect to (i) wells drilled and completed during the periods indicated and (ii) wells drilled in a prior period but completed in the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

Years Ended December 31,

2017

2016

2015

Gross

Net

Gross

Net

Gross

Net

Development wells:

Productive

96

76

95

76

180

116

Dry

1

1

-

-

1

1
Exploratory wells:

Productive

209

112

131

83

260

154

Dry

3

3

1

1

3

2

Total wells:

Productive

305

188

226

159

440

270

Dry (a)

4

4

1

1

4

3

Total

309

192

227

160

444

273

(a)
The dry hole category includes 4 (4 net) wells that were unsuccessful due to mechanical or other issues for the year ended December 31, 2017.

Years Ended December 31,
2019 2018 2017
Gross Net Gross Net Gross Net
Development wells:
Productive 151
124
114
80
96
76
Dry —
—
—
—
1
1
Exploratory wells:
Productive 328
183
236
124
209
112
Dry 3
2
1
1
3
3
Total wells:
Productive 479
307
350
204
305
188
Dry (a) 3
2
1
1
4
4
Total 482
309
351
205
309
192


(a)	The dry hole category includes 2 (1 net) wells and 1 (1 net) well that were unsuccessful due to mechanical issues for the years ended December 31, 2019 and 2018, respectively. Additionally, the dry hole category includes 1 (1 net) well that was incapable of producing hydrocarbons in economic quantities for the year ended December 31, 2019.

Present activities. The following table sets forth information about wells for which drilling was in-progress or are pending completion at December 31, ~~2017,~~2019, which are not included in the above table:

Drilling In-Progress

Pending Completion

Gross

Net

Gross

Net

Development and exploratory wells

35

22

85

49



	Drilling In-Progress		Pending Completion
	Gross	Net	Gross	Net
Development and exploratory wells	34	21	157	95

The following table sets forth a summary ~~information concerning~~of our production and operating data for the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015.~~2017. The actual historical data in this table excludes results from ~~our acquisition of certain assets of Reliance Energy, Inc. (the “Reliance Acquisition”)~~the RSP Acquisition for periods prior to ~~October 2016.~~July 19, 2018. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

Years Ended December 31,

2017

2016

2015

Production and operating data:

Net production volumes:

Oil (MBbl)


43,472

33,840

34,457

Natural gas (MMcf)


161,089

127,481

106,987

Total (MBoe)


70,320

55,087

52,288

Average daily production volumes:

Oil (Bbl)


119,101

92,459

94,403

Natural gas (Mcf)


441,340

348,309

293,115

Total (Boe)


192,658

150,511

143,256

Average prices per unit:


Oil, without derivatives (Bbl)

$
48.13

$
39.90

$
44.69

Oil, with derivatives (Bbl) (a)

$
49.93

$
57.90

$
62.03

Natural gas, without derivatives (Mcf)

$
3.07

$
2.23

$
2.46

Natural gas, with derivatives (Mcf) (a)

$
3.06

$
2.36

$
2.80

Total, without derivatives (Boe)

$
36.78

$
29.68

$
34.49

Total, with derivatives (Boe) (a)

$
37.88

$
41.03

$
46.60

Operating costs and expenses per Boe: (b)


Oil and natural gas production

$
5.80

$
5.81

$
7.46

Production and ad valorem taxes

$
2.82

$
2.38

$
2.90

Depreciation, depletion and amortization

$
16.29

$
21.19

$
23.40

General and administrative

$
3.46

$
4.09

$
4.42

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




Years Ended December 31,

(in millions)

2017

2016

2015

Net cash receipts from derivatives:

Oil derivatives

$
79

$
609

$
597

Natural gas derivatives

-

16

36

Total

$
79

$
625

$
633

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

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



	Years Ended December 31,
	2019		2018		2017
Production and operating data:
Net production volumes:
Oil (MBbl)	76,369		61,251		43,472
Natural gas (MMcf)	266,865		208,326		161,089
Total (MBoe)	120,847		95,972		70,320

Average daily production volumes:
Oil (Bbl)	209,230		167,811		119,101
Natural gas (Mcf)	731,137		570,756		441,340
Total (Boe)	331,086		262,937		192,658

Average prices per unit: (a)
Oil, without derivatives (Bbl)	$	54.03	$	56.22	$	48.13
Oil, with derivatives (Bbl) (b)	$	52.35	$	52.73	$	49.93
Natural gas, without derivatives (Mcf)	$	1.74	$	3.40	$	3.07
Natural gas, with derivatives (Mcf) (b)	$	1.86	$	3.37	$	3.06
Total, without derivatives (Boe)	$	38.00	$	43.25	$	36.78
Total, with derivatives (Boe) (b)	$	37.19	$	40.98	$	37.88

Operating costs and expenses per Boe: (a)
Oil and natural gas production	$	5.93	$	6.14	$	5.80
Production and ad valorem taxes	$	2.89	$	3.19	$	2.82
Gathering, processing and transportation	$	0.96	$	0.58	$	—
Depreciation, depletion and amortization	$	16.25	$	15.41	$	16.29
General and administrative	$	2.69	$	3.25	$	3.46



(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:

		Years Ended December 31,
	(in millions)	2019			2018			2017
	Net cash receipts from (payments on) derivatives:
	Oil derivatives	$	(129	)	$	(213	)	$	79
	Natural gas derivatives	31			(5		)	—
	Total	$	(98	)	$	(218	)	$	79

	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.

Productive Wells

The following table sets forth the number of productive oil and natural gas wells on our properties at December 31, ~~2017, 2016~~2019, 2018 and ~~2015.~~2017. The change in gross and net wells for 2019 as compared to 2018 is primarily attributable to the New Mexico Shelf divestiture. See Note 5 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information. As of December 31, 2019, we did not have any wells with multiple completions. This table does not include wells in which we own a royalty interest only.

Gross Productive Wells

Net Productive Wells

Natural

Natural

Oil

Gas

Total

Oil

Gas

Total

December 31, 2017

Core Operating Areas:

Northern Delaware Basin

1,282

439

1,721

726

213

939

Southern Delaware Basin

319

26

345

195

17

212

Midland Basin

2,747

15

2,762

1,675

6

1,681

New Mexico Shelf

3,200

121

3,321

2,548

44

2,592

Other

-

3

3

-

-

-

Total

7,548

604

8,152

5,144

280

5,424

December 31, 2016

Core Operating Areas:

Northern Delaware Basin

1,164

454

1,618

662

212

874

Southern Delaware Basin

270

27

297

163

17

180

Midland Basin

2,577

15

2,592

1,298

5

1,303

New Mexico Shelf

3,222

126

3,348

2,560

33

2,593

Other

-

3

3

-

-

-

Total

7,233

625

7,858

4,683

267

4,950

December 31, 2015

Core Operating Areas:

Northern Delaware Basin

1,141

460

1,601

651

217

868

Southern Delaware Basin

222

53

275

138

29

167

Midland Basin

2,476

24

2,500

1,173

8

1,181

New Mexico Shelf

3,143

114

3,257

2,531

42

2,573

Other

-

3

3

-

0

0

Total

6,982

654

7,636

4,493

296

4,789



	Gross Productive Wells			Net Productive Wells
	Oil	Natural Gas	Total	Oil	Natural Gas	Total
December 31, 2019
Operating Areas:
Delaware Basin	1,991	574	2,565	1,216	279	1,495
Midland Basin	3,397	16	3,413	2,255	5	2,260
Other	—	3	3	—	—	—
Total	5,388	593	5,981	3,471	284	3,755

December 31, 2018
Operating Areas:
Delaware Basin	4,801	690	5,491	3,569	313	3,882
Midland Basin	3,770	13	3,783	2,437	4	2,441
Other	—	3	3	—	—	—
Total	8,571	706	9,277	6,006	317	6,323

December 31, 2017
Operating Areas:
Delaware Basin	4,801	586	5,387	3,469	274	3,743
Midland Basin	2,747	15	2,762	1,675	6	1,681
Other	—	3	3	—	—	—
Total	7,548	604	8,152	5,144	280	5,424

General. We market our oil and natural gas in accordance with standard energy industry practices. ~~The~~Through our marketing ~~effort endeavors~~efforts we endeavor to obtain the combined highest netback and most secure market available at that time. In addition, marketing supports our operations group as it relates to the planning and preparation of future development activity so that available markets can be assessed and secured. ~~This planning also involves~~

Oil. We generally sell production at the ~~coordination of access~~lease to ~~the physical facilities necessary to connect forthcoming wells as efficiently as possible.~~

~~Oil~~. third-party purchasers. We generally do not transport, refine or process the oil we produce. ~~The majority~~Most of our ~~oil~~Delaware Basin production in ~~southeast~~ New Mexico is connected directly to oil gathering pipelines. Most of our gathered oil from the New Mexico Shelf is utilized in a two-refinery complex in southeast New Mexico. Most of our oil production from the New Mexico portion of our Northern Delaware Basin core area is now connected to the ~~Alpha Crude Connector, LLC (“ACC”) pipeline~~Plains Pipeline, L.P. gathering system. ~~Most of the oil~~This production ~~connected to the ACC pipeline system~~ is then primarily purchased by three different purchasers and moved on several different pipeline outlets connected to ACC. We have assigned our shipping rights on ACC to these purchasers and they purchase our production at the receipt points that are connected at our lease tank batteries into ACC. The remaining oil in our Northern Delaware Basin core area is purchased by approximately five different oil purchasers and trucked to regional pipeline stations.

purchasers.

Most of our ~~oil in the Southern~~ Delaware Basin production in Texas is onconnected to one of ~~three~~five different ~~oil~~ gathering systems. One of these systems is a crude oil gathering and transportation system operated by a subsidiary of Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity in which we own a 23.75 percent membership interest. The oil is then transported to the Crane/Midland/Colorado City pipeline corridor and then onto Cushing or Gulf Coast markets. A significant portion of our Midland Basin production is on one of ~~six~~nine different gathering systems. ~~Most~~The remaining portion of ~~this~~our production is sweet crude and is transported by third parties to Cushing or Gulf Coast markets. The balance of our oil in these areas that is not directly connected to pipelines is trucked to unloading stations on those same pipelines.sold via truck transport. We sell ~~the majority of the~~our produced oil ~~we produce~~ under contracts using market-based ~~pricing. This price~~pricing, which is ~~then~~ adjusted for differentials based upon delivery location and oil quality.

Natural Gas. We consider all natural gas gathering, treating and processing service providers in the areas of our production and evaluate market options to obtain the best price reasonably available given the necessary operating conditions. We sell the majority of our natural gas under individually negotiated natural gas purchase contracts using market-based pricing. The majority of our natural gas is subject to long-term agreements that generally extend five to ten years from the effective date of the subject contract.

The majority of our natural gas is ~~casinghead~~casing head gas, which is sold at the lease location under (i) percentage of proceeds processing contracts, (ii) fee-based contracts or (iii) a hybrid of percentage of proceeds and fee-based contracts. The ~~purchaser gathers~~purchasers generally gather our casinghead natural gas in the field where it is produced and ~~transports~~then transport it via pipeline to natural gas processing plants where natural gas liquid products and residue gas are extracted and ~~sold by the processors. The portion of natural gas remaining after liquid extraction is residue gas, which is placed on residue pipeline systems downstream of the subject processing plant.~~sold. Under our percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, we receive a percentage of the value for the extracted liquids and the residue gas. Under our fee-based contracts, we receive natural gas liquids and residue gas value, less the fee component thereof, or are invoiced the fee component of the purchaser’s service.

Delivery Commitments

Certain of our ~~service.~~

Our Principal Customers

We sell our oil and natural gas production principally to marketers and other purchasers that have access to pipeline facilities. In areas where there is no practical access to pipelines, oil is transported to storage facilities by trucks owned or otherwise arranged by the marketers or purchasers. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.

For ~~2017,~~2019, revenues from oil and natural gas sales to Plains Marketing and Transportation, Inc. and ~~Holly Frontier Refining and Marketing,~~Enterprise Crude Oil LLC accounted for approximately 2117 percent and 10 percent ~~respectively,~~ of our total operating ~~revenues.~~revenues, respectively. While the loss of either ~~of these purchasers~~purchaser may result in a temporary interruption in sales of, or a lower price for, our production, we believe that the loss ~~of either of these purchasers~~ would not have a material adverse effect on our operations, as there are alternative purchasers in our producing regions. See Note 1213 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

Competition

The oil and natural gas industry in the areas in which we operate is highly competitive. We encounter strong competition from numerous parties, ranging generally from small independent producers to major integrated companies. We primarily encounter significant competition in acquiring properties. At higher commodity prices, we also face competition in contracting for drilling, pressure pumping and workover equipment and securing ~~trained~~and retaining qualified personnel. Many of these competitors have financial, technical and personnel resources substantially larger than ours. As a result, our competitors may be able to pay more for desirable properties, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

In addition to competition for drilling, pressure pumping and workover equipment, we are also affected by the availability of related equipment and materials. The oil and natural gas industry periodically experiences shortages of drilling and workover rigs, equipment, pipe, materials and personnel, which can delay drilling, workover and exploration activities and cause significant price increases. We are not experiencing material shortages at this time but are unable to predict the timing or duration of any such future shortages.

Working Capital

Based on current market conditions, we have maintained a stable liquidity position. Our principal source of liquidity is available borrowing capacity under our credit ~~facility.~~facility, as amended and restated (our “Credit Facility”). At December 31, ~~2017,~~2019, we had ~~$322~~a cash balance of $70 million ~~of debt outstanding~~and did not have any borrowings under our ~~credit facility and $1.7~~Credit Facility. Additionally, we had approximately $2.0 billion of unused commitments under our credit facility. Subsequent to December 31, 2017, our cash position increased by approximately $250 million as a result of completing two divestitures of oil and natural gas properties located in the Southern Delaware Basin core area.Credit Facility. Our primary needs for cash are development, exploration and acquisitions of oil and natural gas assets, payment of contractual obligations and working capital obligations. However, additional borrowings under our ~~credit facility~~Credit Facility or the issuance of additional debt securities will require a greater portion of our cash flow from operations to be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions.

Applicable Laws and Regulations

Regulation of Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and the plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental, Health and Safety Matters

General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws, rules and regulations may, among other things:

require the acquisition of various permits before drilling commences;

require notice to stakeholders of proposed and ongoing operations;

require the installation of ~~expensive pollution~~emission control equipment;

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities;

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, or otherwise restrict or prohibit activities that could impact the environment, including water resources; and

require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws, rules and regulations may also restrict the production rate of oil and natural gas below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Additionally, environmental laws and regulations are revised frequently, and any changes, including changes in implementation or interpretation, that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules and regulations to which our business is subject.

Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to regulatory guidance issued by the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and certain environmental organizations entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is

not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Each state ~~including Texas,~~ also has environmental cleanup laws analogous to CERCLA.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose storage, treatment and disposal of hazardous substances, wastes or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination.

Water discharges. The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including dredge and fill activities in regulated wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA, or, in some circumstances, the U.S. Army Corps of Engineers (the “Corps”), or an analogous state agency. In addition, spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. Further, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

In September 2015, new EPA and U.S. Army Corps of Engineers rules to revise the definition of “waters of the United States” (“WOTUS”) for all Clean Water Act programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. To the extent the rule expands the scope of jurisdiction of the Clean Water Act, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act programs, and implementation of the rule has been stayed pending resolution of the court challenge. In response to this decision, On January 23, 2020, the EPA and the Corps ~~resumed nationwide use~~issued the “Navigable Waters Protection Rule,” which narrows the scope of waters federally regulated under the Clean Water Act. The former regulation that had attempted to define the scope of the agencies’ prior regulations defining the term “waters of the United States.” Those regulations will be implemented as they were prior to the effective date of the new WOTUS rule. In January 2017, the U.S. Supreme Court accepted review of the WOTUS rule to determine whether jurisdiction to hear challenges to the rule rests with the federal district or appellate courts. In February 2017, the new Presidential administration issued an Executive Order directing the EPA and the Corps to review and, consistent with applicable law, to initiate a rule-making to rescind or revise the WOTUS rule. The EPA and the Corps published a notice of intent to review and rescind or revise the rule in March 2017. In addition, the U.S. Department of Justice filed a motion with the U.S. Supreme Court in March 2017 requesting that the U.S. Supreme Court stay the suit concerning which court should hear challenges to the rule. The U.S. Supreme Court denied the motion in April 2017. In June 2017, the EPA and the U.S. Army Corps proposed a rule that would initiate the first step in a two-step process intended to review and revise the definition of “waters“Waters of the United States” ~~consistent with President Trump’s Executive Order. Under~~(the “2015 Rule”) was repealed in 2019. Litigation over the ~~proposal,~~“Navigable Water Protection Rule” and the ~~first step would be to rescind the May 2015 final rule and put back into effect the narrower language defining “waters~~repeal of the ~~United States”~~2015 Rule are expected to continue. An expansion of the scope of the definition of jurisdictional waters subject to regulation under the Clean Water Act that existed prior to the rule. The second step would be a notice-and-comment rule-making in which the agencies will conduct a substantive reevaluation of the definition of “waters of the United States.” Finally, in January 2018, the Supreme Court ruled that the WOTUS rule must first be reviewed in federal district courts, remanding the case at issue to the district level and putting the status of the Sixth Circuit’s stay of the new rule into question. Citing uncertainty caused by litigation, the EPA subsequently announced a two year stay of the application of the rule as it undertakes its own review of the rule.

could increase our compliance costs.

Safe Drinking Water Act.Our oil and natural gas exploration and production operations generate produced water, drilling muds, and other waste streams, some of which may be disposed via injection in underground wells situated in non-producing subsurface formations. The drilling and operation of these injection wells are regulated by the federal Safe Drinking Water Act (the “SDWA”). The Underground Injection Well Program under the SDWA requires that we obtain permits from the EPA or delegated state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts the types and quantities of fluids that may be injected and prohibits the migration of fluid containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental

agencies, incurrence of expenditures for remediation of affected resources, and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages, and personal injuries. Any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and would ultimately increase the cost of our operations, which costs could be significant. For example, in 2014 the Railroad Commission of Texas (the “RRC”) adopted additional permit rules for injection wells to address seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. Furthermore, in response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. For example, in 2016, the Oklahoma Corporation Commission issued various orders and regulations applicable to disposal operations in specific counties in Oklahoma. These rules require that disposal well operators, among other things, conduct additional mechanical integrity testing, make sure that their wells are not injecting wastes into targeted formations, and/or reduce the volumes of wastes disposed in such wells. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase, and our ability to continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position.

Air emissions. The federal Clean Air Act (the “CAA”), and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. These and other laws and regulations may increase the costs of compliance for some facilities where we operate. Obtaining or renewing permits also has the potential to delay the development of our projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources.

For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, in June 2016, the EPA finalized rules under the CAA regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities (such as tank batteries), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. In a separate rulemaking in June 2016, the EPA finalized new air emission control requirements for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The final rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, and also imposes leak detection and repair requirements on operators. In addition, the rule package extends existing volatile organic compound (“VOC”) standards under the EPA’s Subpart OOOO of the New Source Performance Standards to include previously unregulated equipment within the oil and natural gas source category. However, in June 2017, the EPA proposed a two year stay of the fugitive emissions monitoring requirements, pneumatic pump standards, and closed vent system certification requirements in the 2016 New Source Performance Standards rule for the oil and gas industry while it reconsiders these aspects of the rule. The proposal is still under consideration. The U.S. Bureau of Land Management (“BLM”) finalized similar rules in November 2016 that limit methane emissions from new and existing oil and natural gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements. The BLM adopted final rules in January 2017. Operators generally had one year from the January 2017 effective date to come into compliance with the rule’s requirements. However, in December 2017, the BLM temporarily suspended or delayed certain of these requirements set forth in its Venting and Flaring Rule until January 2019, pending administrative review of the rule. These air emission rules have the potential to increase our compliance costs.

Climate change. In response to findings that emissions of carbon dioxide, methane and other “greenhouse gases” (“GHGs”) present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of GHGs under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of GHG

emissions from specified large GHG emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis, including GHG emissions resulting from the completion and workover operations of hydraulically fractured oil wells. Recent federal regulatory action with respect to climate change has focused on methane emissions. ~~As noted above, both~~Both the EPA and the ~~BLM~~U.S. Bureau of Land Management (the “BLM”) finalized rules in 2016 that limit methane emissions from upstream oil and natural gas exploration and production operations. Increased regulation of methane and other GHGs have the potential to result in increased compliance costs and, consequently, adversely affect our operations.

On In addition, in August ~~3, 2015,~~2019, the EPA ~~also~~ issued ~~new regulations limiting~~the Affordable Clean Energy rule (“ACE”) that designates heat rate improvement, or efficiency improvement, as the best system of emissions reduction for carbon dioxide ~~emissions~~ from existing power generation facilities. Under this rule, nationwide carbon dioxide emissions would be reduced by approximately 30 percent from 2005 levels by 2030 with a flexible interim goal. Several industry groups and states challenged the rule. On February 9, 2016, the

coal-fired electric utility generating units.

U.S. Supreme Court stayed the implementation of this rule pending judicial review. On March 28, 2017, President Trump signed an Executive Order directing the EPA to review the regulations, and on April 4, 2017, the EPA announced that it was reviewing the 2015 carbon dioxide regulations. On April 28, 2017, the U.S. Court of Appeals for the District of Columbia stayed the litigation pending the current administration’s review. That stay was extended for another 60 days on August 8, 2017. On October 10, 2017, the EPA initiated the formal rulemaking process to repeal the regulations. The EPA’s proposal will be subject to public comment and likely legal challenge, and as such, we cannot predict at this time what impact the rulemaking will have on the demand for oil and natural gas production and our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce emissions of GHGs in recent years. In the absence of Congressional action, many states have established rules aimed at reducing GHG emissions, including GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In addition, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. It should also be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and gas companies in connection with their ~~greenhouse gas~~GHG emissions. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

Hydraulic fracturing.Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing as part of our operations. The process is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel and issued guidance in February 2014 governing such activities. The EPA has also issued final regulations under the CAA establishing performance standards, including standards for the capture of ~~VOCs~~volatile organic compounds (“VOCs”) and methane released during hydraulic fracturing (although the EPA has temporarily suspended or delayed compliance with certain of these standards as they undergo an administrative review); an advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and final rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, New Mexico and Texas have adopted hydraulic fracturing fluid disclosure requirements, and the RRC has also adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. In addition, local governments have also taken steps to regulate hydraulic fracturing, including imposing restrictions or moratoria on oil and natural gas activities occurring within their boundaries. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.

We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our well control, general liability and excess liability insurance policies may cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies. If new laws or regulations significantly restrict hydraulic fracturing activities or impose burdens on new permitting or operating requirements, our ability to utilize hydraulic fracturing may be curtailed, and this may in turn reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Operations on Federal Lands.We currently operate on federal lands under the jurisdiction of the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the state permitting process. Delays in obtaining permits necessary can disrupt our operations and have an adverse effect on our business. ~~As noted above, in~~In November 2016, the BLM finalized rules that restrict methane emissions from oil and natural gas activities on federal lands by limiting venting and flaring of natural gas from wells and other equipment. The final rule also requires operators to pay royalties to the BLM on flared gas from wells already connected to gas capture infrastructure, and allows the agency to set royalty rates at or above 12.5 percent of the value of production. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations.

Endangered species.The federal Endangered Species Act (the “ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our drilling operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete drilling and developmental operations and could adversely affect our future production from those areas. The designation of previously unprotected species as threatened or endangered in areas where we or our oil and natural gas exploration and production customers operate could cause us or our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of ~~operations, which could reduce demand for our midstream services.~~

operations.

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or even halt development of some of our oil and natural gas projects.

OSHA and other laws and regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety.

We are not aware of any existing environmental issues, claims or regulations that will require us to incur material capital expenditures during ~~2018,~~2020, and we did not incur material capital expenditures relating to environmental issues, claims or regulations during ~~2017.~~2019. However, we cannot assure that the passage or application of more stringent laws or regulations or the application of existing laws in the future will not require us to incur material capital expenditures or have a material adverse effect on our financial position or results of operations.

Our Employees

Our corporate headquarters are located at One Concho Center, 600 West Illinois Avenue, Midland, Texas ~~79701.~~79701 and have administrative offices in both Houston, Texas and Dallas, Texas. We also maintain various field offices in Texas and New Mexico. At December 31, ~~2017,~~2019, we had ~~1,203~~1,453 employees, ~~457~~511 of whom were employed in field operations. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work

stoppages. We consider our relations with our employees to be good. ~~We also utilize the services of contractors to perform various field and other services.~~

Available Information

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the U.S. Securities and Exchange Commission (the “SEC”) under the Exchange Act. The public may read and copy any materials that we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file or furnish electronically with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov.

We also make available free of charge through our website, www.concho.com, our ~~Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those~~ reports ~~filed~~that we file or ~~furnished pursuant to Section 13(a) of~~furnish with the ~~Exchange Act~~SEC as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

Reconciliation of Standardized Measure to PV-10

PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of the GAAP standardized measure of discounted future net cash flows to PV-10 (non-GAAP) at December 31, ~~2017, 2016~~2019, 2018 and ~~2015:~~

December 31,
(in millions)

2017

2016

2015

Standardized measure of discounted future net cash flows

$
7,478

$
4,190

$
3,739
Present value of future income taxes discounted at 10%

1,001

652

524

PV-10

$
8,479

$
4,842

$
4,263

2017:



(in millions)	December 31,
(in millions)	2019		2018		2017
Standardized measure of discounted future net cash flows	$	9,583	$	15,555	$	7,478
Present value of future income taxes discounted at 10%	1,000		2,392		1,001
PV-10	$	10,583	$	17,947	$	8,479

Reconciliation of Net Income (Loss) to Adjusted EBITDAX

Adjusted EBITDAX (as defined below) is presented herein and reconciled from the GAAP measure of net income (loss) because of its wide acceptance by the investment community as a financial indicator.

We define adjusted EBITDAX as net income (loss), plus (1) exploration and abandonments, (2) depreciation, depletion and amortization, (3) accretion of discount on asset retirement obligations, (4) impairments of long-lived assets, (5) impairments of goodwill, (6) non-cash stock-based compensation, ~~(6)~~(7) (gain) loss on derivatives, ~~(7)~~(8) net cash receipts from (payments on) derivatives, ~~(8)~~(9) (gain) loss on disposition of assets ~~net, (9)~~and other, (10) interest expense, ~~(10)~~(11) loss on extinguishment of debt, ~~(11) federal~~(12) gain on equity method investments, (13) RSP transaction costs and ~~state~~(14) income tax expense (benefit) ~~from continuing operations and (12) similar items listed above that are presented in discontinued operations.~~. Adjusted EBITDAX is not a measure of net income (loss) or cash flows as determined by GAAP.

Our adjusted EBITDAX measure provides additional information that may be used to better understand our operations. Adjusted EBITDAX is one of several metrics that we use as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to, or more meaningful than, net income (loss) as an indicator of operating performance. Certain items excluded from adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Adjusted EBITDAX, as used by us, may not be comparable to similarly titled measures reported by other companies. We believe that adjusted EBITDAX is a widely followed measure of operating performance and is one of many metrics used by our management team and by other users of our consolidated financial statements. For example, adjusted EBITDAX can be used to assess our operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure, and to assess the financial performance of our assets and our ~~company~~Company without regard to capital structure or historical cost basis.

Adjusted EBITDAX, as used herein, may not be comparable to similarly titled measures reported by other companies.

The following table provides a reconciliation of the GAAP measure of net income (loss) to adjusted EBITDAX (non-GAAP) for the periods indicated:

Years Ended December 31,
(in millions)

2017

2016

2015

2014

2013

Net income (loss)

$
956

$
(1,462)

$
66

$
538

$
251

Exploration and abandonments

59

77

59

285

109

Depreciation, depletion and amortization

1,146

1,167

1,223

980

773

Accretion of discount on asset retirement obligations

8

7

8

7

6

Impairments of long-lived assets

-

1,525

61

447

65

Non-cash stock-based compensation

60

59

63

47

35

(Gain) loss on derivatives

126

369

(700)

(891)

124

Net cash receipts from (payments on) derivatives

79

625

633

72

(32)

(Gain) loss on disposition of assets, net

(678)

(118)

54

9

1

Interest expense

146

204

215

217

219

Loss on extinguishment of debt

66

56

-

4

29

Income tax expense (benefit) from continuing operations

(75)

(876)

31

318

118

Discontinued operations

-

-

-

-

(12)
EBITDAX

$
1,893

$
1,633

$
1,713

$
2,033

$
1,686



(in millions)	Years Ended December 31,
(in millions)	2019			2018			2017			2016			2015
Net income (loss)	$	(705	)	$	2,286		$	956		$	(1,462	)	$	66
Exploration and abandonments	201			65			59			77			59
Depreciation, depletion and amortization	1,964			1,478			1,146			1,167			1,223
Accretion of discount on asset retirement obligations	10			10			8			7			8
Impairments of long-lived assets	890			—			—			1,525			61
Impairments of goodwill	282			—			—			—			—
Non-cash stock-based compensation	85			82			60			59			63
(Gain) loss on derivatives	895			(832		)	126			369			(700		)
Net cash receipts from (payments on) derivatives	(98		)	(218		)	79			625			633
(Gain) loss on disposition of assets and other	(456		)	(800		)	(678		)	(118		)	54
Interest expense	185			149			146			204			215
Loss on extinguishment of debt	—			—			66			56			—
Gain on equity method investments	(17		)	(103		)	—			—			—
RSP transaction costs	—			32			—			—			—
Income tax expense (benefit)	(154		)	603			(75		)	(876		)	31
Adjusted EBITDAX	$	3,082		$	2,752		$	1,893		$	1,633		$	1,713

You should consider carefully the following risk factors together with all of the other information included in this report and other reports filed with the SEC before investing in our securities. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our securities could decline and you could lose all or part of your investment.

Risks Related to Our Business

Oil ~~natural gas~~ and natural gas ~~liquid~~ prices are volatile. A decline in oil and natural gas ~~and~~ ~~natural gas liquid~~ prices could adversely affect our financial position, financial results, cash flow, access to capital and ability to grow.

Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production and the prices prevailing from time to time for oil and natural ~~gas~~gas. Oil and natural gas ~~liquids. Oil, natural gas and natural gas liquid~~ prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the amount of cash flow we have available for capital expenditures and our ability to borrow money or raise additional capital. The prices and levels of production for oil ~~natural gas~~ and natural gas ~~liquids~~ are subject to a variety of factors beyond our control, including:

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

·gas;

the ~~domestic and foreign~~overall global supply of oil ~~natural gas~~ and natural ~~gas liquids;~~

·gas;

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

•

the U.S. economy,

•

weather conditions, and

•

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

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 West Texas and Southeast New Mexico and the level of commodity inventory in the Permian Basin;

economic conditions ~~worldwide;~~

·worldwide, including adverse conditions driven by political, health or weather events;

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

volatility and trading patterns in the commodity-futures markets;

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

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

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 sources of 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;~~

·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 so as to materially reduce emissions of carbon dioxide and methane GHGs;

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

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

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

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

·~~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;~~

the quality of the oil we produce; and

the price, availability and ~~availability~~acceptance of alternative fuels.

Furthermore, oil and natural gas prices continued to be volatile in ~~2017.~~2019. For example, ~~the~~ NYMEX oil prices in ~~2017~~2019 ranged from a high of ~~$60.42~~$66.30 to a low of ~~$42.53~~$45.41 per Bbl and the NYMEX natural gas prices in ~~2017~~2019 ranged from a high of ~~$3.72~~$3.59 to a low of ~~$2.56~~$2.07 per MMBtu. ~~Further, the NYMEX oil prices and NYMEX natural gas prices reached highs of $66.14 per Bbl and $3.63 per MMBtu, respectively, during the period from January 1, 2018 to February 16, 2018.~~

Declines in oil ~~natural gas~~ and natural gas ~~liquid~~ prices would not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically. This in turn would lower the amount of oil and natural gas reserves we could recognize and, as a result, could have a material adverse effect on our financial condition and results of operations. If the oil and natural gas industry experiences significant price declines for a sustained period, ~~such as those experienced in 2015 to 2017,~~ we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future indebtedness or obtain additional capital on attractive terms, all of which can adversely affect the value of our securities.

Approximately 3026 percent of our total estimated proved reserves at December 31, ~~2017~~2019 were undeveloped, and those reserves may not ultimately be developed.

At December 31, ~~2017,~~2019, approximately 3026 percent of our total estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserves data assumes that we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. Our reserve report at December 31, ~~2017~~2019 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately ~~$2.3~~$2.4 billion. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to write-off these reserves. In addition, under the SEC’s reserve rules, because proved undeveloped reserves may be recognized only if they relate to wells planned to be drilled within five years of the date of their initial recognition, we may be required to write-off any proved undeveloped reserves that are not developed within this five-year ~~timeframe.~~time frame. For example, as of December 31, ~~2017,~~2019, we wrote-off approximately 61 28 MMBoe of proved undeveloped reserves primarily because ~~they are~~we no longer ~~expected~~expect to ~~be developed~~develop these reserves within five years of the date of their initial recognition.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could cause our costs to increase or production volumes to decrease, which would reduce our cash flows.

Our future financial condition and results of operations depend on the success of our exploration and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil orand natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical or less economical than forecasted. Further, many factors may curtail, delay or cancel drilling, including the following:

·~~shortages of or delays in obtaining equipment and qualified personnel or in obtaining sand or water for hydraulic fracturing activities;~~

delays imposed by or resulting from compliance with regulatory and contractual requirements;

reductions in oil ~~natural gas~~ and natural gas ~~liquid~~ prices;

delays and costs of drilling wells on lands subject to complex development terms and circumstances;

oil or natural gas gathering, transportation and processing availability restrictions or limitations;

pressure or irregularities in geological formations;

equipment failures or accidents;

adverse weather ~~conditions;~~

·~~political events, public protests, civil disturbances, terrorist acts or cyber attacks;~~

·conditions and natural disasters;

environmental hazards, such as natural gas leaks, hydrogen sulfide (“H2S”) treating capacity constraints, oil and produced water spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

surface access restrictions;

failure to obtain regulatory and third-party approvals;

actions by third-party operators of our ~~properties;~~

properties, including offsetting fracturing stimulation operations;

political events, public protests, civil disturbances, terrorist acts or cyber attacks;

shortages of or delays in obtaining equipment and qualified personnel or in obtaining sand or water for hydraulic fracturing activities;

·loss of title or other title related issues;

·~~delays and costs of~~ ~~drilling wells on lands subject to complex development terms and circumstances;~~

·~~oil, natural gas liquids or natural gas gathering, transportation and processing availability restrictions or limitations;~~

limitations in the market for oil ~~natural gas~~ and natural ~~gas liquids;~~gas; and

limited availability of financing at acceptable terms.

The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities. Moreover, certain of these events could result in environmental pollution and impact to third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant damage to property and natural resources.

In addition, the results of our exploratory drilling, including well spacing tests, in new or emerging plays are more uncertain than drilling results in areas that are developed and have established production. Since new or emerging plays and new formations have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

Multi-well pad drilling and project development may result in volatility in our operating results.

We utilize multi-well pad drilling and project development where practical. Project development may involve more than one multi-well pad being drilled and completed at one time in a relatively confined area. Wells drilled on a pad or in a project may not be brought into production until all wells on the pad or project are drilled and completed. Problems affecting one pad or a single well could adversely affect production from all of the wells on the pad or in the entire project. As a result, multi-well pad drilling and project development can cause delays in the scheduled commencement of production, or interruptions in ongoing production. These delays or interruptions may cause declines or volatility in our operating results due to timing as well as declines in oil and natural gas prices. Further, any delay, reduction or curtailment of our development and producing operations, due to operational delays caused by multi-well pad drilling or project development, or otherwise, could result in the loss of acreage through lease expirations.

Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity.

We could experience adverse impacts associated with a high concentration of activity and tighter drilling spacing.

We are subject to drilling, completion and operating risks, including our ability to efficiently execute large-scale project development, as we could experience delays, curtailments and other adverse impacts associated with a high concentration of activity and tighter drilling spacing. A higher concentration of activity and tighter drilling spacing may increase the risk of unintentional communication with other adjacent wells and the potential to reduce total recoverable reserves from the reservoir. If these risks materialize and negatively impact our results of operations relative to guidance or market expectations, and the research analysts who cover our Company may downgrade our common stock or change their recommendations or earnings or performance estimates, which may result in a decline in the market price of our common stock.

Prolonged decreases in our drilling program may require us to pay certain non-use fees or impact our ability to comply with certain contractual requirements.

~~Oil prices declined substantially during the second half of 2014 and continued to decline through 2016, but began to recover in 2017.~~

In the event that oil prices ~~declined~~decline for a sustained period, we may experience significant decreases in drilling activity. Due to the nature of our drilling programs and the oil and natural gas industry in general, we are a party to certain agreements that require us to meet various contractual obligations or require us to utilize a certain amount of goods or services, including, but not limited to, water commitments, throughput volume commitments, power commitments and drilling commitments. In the event that oil and natural gas prices decrease, and as a result continue to reduce the demand for drilling and production, this could lead to a decrease in our drilling activity and production levels, which could, in turn, require us to pay for unutilized goods or services or impact our ability to meet these contractual ~~obligations.~~

obligations, including drilling commitments that may result in lease expirations if unmet.

We may incur losses as a result of title defects in our oil and natural gas properties.

It is our practice to initially conduct only a cursory title review of the oil and natural gas properties on which we do not have proved reserves. To the extent title opinions or other investigations prior to our commencement of drilling operations reflect defects

affecting such properties, we are typically responsible for curing any such defects at our expense. Additionally, the discovery of any such defects could delay or prohibit the commencement of drilling operations on the affected properties. These impacts and other potential losses resulting from title defects in our oil and natural gas properties could have a material adverse effect on our business, financial condition and results of operations.

Our operations are substantially dependent on the availability of ~~water.~~water and our ability to dispose of produced water gathered from drilling and production activities. Restrictions on our ability to obtain water or dispose of produced water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of both the drilling and hydraulic fracturing processes. ~~Historically, we~~West Texas and Southeast New Mexico have ~~been able to purchase water from local land owners and other sources for use in our operations. Over the past few years,~~experienced extreme drought conditions ~~persisted~~ in ~~west Texas~~the past and ~~southeast New Mexico. Although conditions have improved,~~ we cannot guarantee what conditions may occur in the future. Severe drought conditions can result in local water districts taking steps to restrict the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

In addition, we must dispose of the fluids produced from oil and natural gas production operations, including produced water, which we do directly or through the use of third-party vendors. The legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern arises from recent seismic events near underground disposal wells that are used for the disposal by injection of produced water resulting from oil and natural gas activities. In March 2016, the United States Geological Survey identified Texas and Colorado as being among the states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and natural gas extraction. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells to assess any relationship between seismicity and the use of such wells. For example, in Texas, the RRC adopted new rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and natural gas in order to address these seismic activity concerns within the state. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. States may issue orders to temporarily shut down or to curtail the injection depth of existing wells in the vicinity of seismic events.

Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us or by commercial disposal well vendors whom we may use from time to time to dispose of produced water. Increased regulation and attention given to induced seismicity could also lead to greater opposition, including litigation to limit or prohibit oil and natural gas activities utilizing injection wells for produced water disposal.

Any one or more of these developments may result in us or our vendors having to limit disposal well volumes, disposal rates and pressures or locations, or require us or our vendors to shut down or curtail the injection into disposal wells, which events could have a material adverse effect on our business, financial condition and results of operations.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions or delays and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of our drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the SDWA’s Underground Injection Control Program and issued guidance in February 2014, governing such activities. The EPA has also issued: final regulations under the CAA establishing performance standards, including standards for the capture of VOCs and methane released during hydraulic fracturing (although the EPA has temporarily suspended or delayed compliance with certain of these standards as they undergo an administrative review); an advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and final rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

Moreover, in March 2015, the BLM issued a final rule that imposes requirements on hydraulic fracturing activities on federal and Indian lands, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water. However, the BLM lacked authority to promulgate the rule. While that decision was on appeal, the BLM rescinded this rule in December 2017. In January 2018, the state of California and a coalition of environmental groups filed a lawsuit in the Northern District of California to challenge the BLM’s rescission of the 2015 rule. This litigation is ongoing and future implementation of the rule is uncertain at this time.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.

If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements and could also result in permitting delays and potential cost increases. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Climate change legislation, regulations restricting emissions of “greenhouse gases” or legal or other action taken by public or private entities related to climate change could result in increased operating costs and reduced demand for the ~~crude~~ oil and natural gas that we produce.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of GHGs under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis, including GHG emissions resulting from the completion and workover operations of hydraulically fractured oil wells. Recent federal regulatory action with respect to climate change has focused on methane emissions. ~~For example,~~ in June 2016, the EPA finalized new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The final rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, and also imposes leak detection and repair requirements on operators. The BLM finalized similar rules in November 2016 that limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements. The BLM adopted the final rules in January 2017. Operators generally had one year from the January 2017 effective date to come into compliance with the rule’s requirements. ~~However,~~

~~in December 2017, the BLM temporarily suspended or delayed certain of these requirements set forth in its Venting and Flaring Rule until January 2019, pending administrative review of the rule.~~ These methane emission rules have the potential to increase our compliance costs.

See “Item 1. Business—Applicable Laws and Regulations—Environmental, Health and Safety Matters” for additional information.

In the future, the United States may also choose to adhere to international agreements targeting GHG reductions.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. It should also be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their GHG emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors

are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors.

The ultimate impact of GHG emissions-related agreements, legislation and measures on our company’s financial performance is highly uncertain because the Company is unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and tradeoffs that inevitably occur in connection with such processes.

Estimates of proved reserves and future net cash flows are not precise. The actual quantities of our proved reserves and our future net cash flows may prove to be lower than estimated.

Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. Our estimates of proved reserves and related future net cash flows are based on various assumptions, which may ultimately prove to be inaccurate.

Petroleum engineering is a subjective process of estimating accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including the following:

historical production from the area compared with production from other producing areas;

the assumed effects of regulations by governmental agencies;

the quality, quantity and interpretation of available relevant data;

assumptions concerning future commodity prices; and

assumptions concerning future operating costs, severance, excise and ad valorem taxes, development costs, gathering, processing and transportation costs and workover and remedial costs.

Because all reserve estimates are to some degree subjective, each of the following items, or other items not identified below, may differ materially from those assumed in estimating reserves:

the quantities of oil and natural gas that are ultimately recovered;

the production and operating costs incurred;

the amount and timing of future development expenditures; and

future commodity prices.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same ~~data.~~data, and improvements or other changes in geological, geophysical and engineering evaluation methods may cause reserve estimates to change over time. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.

As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on the average previous twelve months first-of-month prices preceding the date of the estimate and costs as of the date of the estimate, while

actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

the amount and timing of actual production;

levels of future capital spending;

increases or decreases in the supply of or demand for oil ~~natural gas liquids~~ and natural gas; and

changes in governmental regulations or taxation.

Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. Therefore, the estimates of discounted future net cash flows in this report should not be construed as accurate estimates of the current market value of our proved reserves.

Our business requires substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the acquisition, exploration and development of oil and natural gas reserves. At December 31, ~~2017,~~2019, we ~~had approximately $322 million of~~did not have any debt outstanding under our ~~credit facility~~Credit Facility (and total debt at December 31, ~~2017~~2019 of ~~$2.7~~$4.0 billion), and we had approximately ~~$1.7~~$2.0 billion of unused commitments under our ~~credit facility.~~Credit Facility. Expenditures for acquisition, exploration and development of oil and natural gas properties are the primary use of our capital resources. We incurred approximately ~~$2.9~~$3.1 billion in acquisition, exploration and

development costs during the year ended December 31, ~~2017.~~2019. In February ~~2018, we announced~~2020, our ~~2018~~board of directors approved our 2020 capital budget ~~excluding acquisitions,~~ of ~~approximately $2.0 billion with expected capital spending~~up to ~~range~~$2.9 billion. We expect to spend between ~~$1.9~~$2.6 billion and ~~$2.1 billion.Our 2018 capital budget, based~~$2.8 billion on ~~our current expectations of commodity prices~~drilling and ~~costs, is expected to be funded with our cash flows.~~completion activity. We plan to spend approximately ~~$2.3~~$2.4 billion over the next five years on future development costs associated with proved undeveloped reserves.

We intend to finance our future capital expenditures, other than significant acquisitions, through cash flow from operations and, if necessary, through borrowings under our ~~credit facility.~~Credit Facility. However, our cash flow from operations and access to capital are subject to a number of variables, including:

the ~~level~~volume of oil and natural gas we are able to produce from existing wells;

our ability to transport our oil and natural gas to market;

the prices at which our commodities are sold;

the costs of producing oil and natural gas;

global credit and securities markets;

the ability and willingness of lenders and investors to provide capital and the cost of the capital;

our ability to acquire, locate and produce new reserves;

· and

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

·~~our proved reserves.~~

ratings.

We may not generate expected cash flows and may have limited ability to obtain the capital necessary to sustain our operations at current or anticipated levels. A decline in cash flow from operations or our financing needs may require us to revise our capital program or alter or increase our capitalization substantially through the issuance of debt or equity securities. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. Additional borrowings under our ~~credit facility~~Credit Facility or the issuance of additional debt securities will require that a greater portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. In addition, our ~~credit facility~~Credit Facility imposes certain limitations on our ability to incur additional indebtedness other than indebtedness under our ~~credit facility.~~Credit Facility. If we desire to issue additional debt securities other than as expressly permitted under our ~~credit facility,~~Credit Facility, we will be required to seek the consent of the lenders in accordance with the requirements of ~~the credit facility,~~our Credit Facility, which consent may be withheld by the lenders at their discretion. Additional financing also may not be available on acceptable terms or at all. In the event additional capital resources are unavailable, we may curtail drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.

The failure to obtain additional financing could result in a curtailment of our operations relating to the development of our undeveloped acreage or the curtailment of acquisitions that may be favorable to us, which in turn could lead to a decline in our oil and natural gas reserves, and could adversely affect our production, revenues and results of operations.

A decline in general economic, business or industry conditions could have a material adverse effect on our results of operations.

A global economic downturn, particularly with respect to the U.S. economy or the oil and natural gas industry, and global financial and credit market disruptions reduce the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide, which can result in a slowdown in economic activity. Reduced worldwide demand for energy often results in lower commodity prices, which will reduce our cash flows and may affect our borrowing ability. WeIf the economic climate in the United States or abroad deteriorates, we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of oil and natural gas that we can produce economically, which could ultimately decrease our net revenue and profitability.

~~Recently enacted legislation will affect~~ In addition, reduced worldwide demand for securities issued by oil and natural gas companies or depressed trading prices of the debt and equity securities of oil and natural gas companies generally may depress the market value of our ~~tax position; however, certain~~securities or make it more difficult for us to raise capital.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated. Additional state taxes on oil and natural gas extraction may be imposed, as a result of future legislation.

In December 2017, Congress enacted the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (“TCJA”). The law made significant changes to U.S. federal income tax laws, including reducing the corporate income tax rate from 35 percent to 21 percent, repealing the corporate alternative minimum tax (“AMT”), partially limiting the deductibility of interest expense and net operating losses (“NOLs”), eliminating the deduction for certain U.S. production activities and allowing the immediate deduction of certain new investments in lieu of depreciation expense over time. Many aspects of the TCJA are unclear and may not be clarified for some time. We will continue to monitor any new administrative guidance or tax law interpretation.

In recent years, U.S. lawmakers have proposed certain significant changes to U.S. tax laws applicable to oil and natural gas companies. These changes include, but are not limited to: (i) the elimination of current deductions for intangible drilling and development costs; (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these changes were not included in the ~~TCJA,~~budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (“TCJA”), it is unclear whether any such changes will be enacted or if enacted, when such changes could be effective. If such proposed changes (or the imposition of, or increases in, production, severance or similar taxes) were to be enacted, as well as any similar changes in state, local or non-U.S. law, it could

eliminate or postpone certain tax deductions that are currently available to us with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and natural gas extraction. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil and natural gas.

Our ability to use our existing net operating loss carryforwards or other tax attributes could be limited.

At December 31, ~~2017,~~2019, we had approximately ~~$122 million~~$2.6 billion of federal ~~NOL~~net operating loss (“NOL”) carryforwards available to offset against future taxable income. ~~These~~Of these NOL carryforwards, $1.5 billion were generated prior to the effective date of new limitations on utilization of NOLs imposed by the TCJA and are allowable as a deduction against 100 percent of taxable income in future years but will begin to expire in the tax year ~~2036.~~ 2034. The remaining federal NOL of $1.1 billion is subject to an 80 percent limitation but has an indefinite carryforward life. Included in our $2.6 billion of federal NOL carryforwards is approximately $516 million net NOLs that we acquired as part of the RSP Acquisition. This acquired tax NOL, $40 million of research and development (“R&D”) credits and $38 million of interest expense limitation carryforwards (“tax attributes”) are subject to an annual limitation under Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”). However, based on the annual limitation amount, our acquired tax attributes are considered more likely than not to be utilized.

Utilization of any ~~NOL~~tax attribute depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 ~~of the Internal Revenue Code of 1986, as amended (“Section 382”),~~ generally imposes an annual limitation on the amount of ~~NOLs~~tax attributes that may be used to offset taxable income and tax liability when a corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least five percent of our stock change their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change has occurred, or were to occur, utilization of all of our ~~NOLs~~tax attributes, including those acquired from RSP, would be subject to an annual limitation under Section 382, determined by multiplying the value of our equity at the time of the ownership change by the applicable long-term tax-exempt rate as defined in Section 382, and potentially increased for certain gains recognized within five years after the ownership change if we have a net built-in gain in our assets at the time of the ownership change. Any unused annual limitation may be carried over to later years. We do not believe that an ownership change has occurred as a result of our ~~recent~~ equity offerings or our issuance of shares in connection with various acquisitions. As such, Section 382 ~~was~~is not expected to limit our ability to utilize our NOL carryforward or any other tax ~~attribute~~attributes at December 31, ~~2017.~~2019. Future ownership changes or future regulatory changes could limit our ability to utilize our ~~NOLs.~~tax attributes. To the extent we are not able to offset our future income with our NOLs or tax liability with tax credits, this could adversely affect our operating results and cash flows once we attain profitability.

We have substantial indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

We had approximately $~~2.7~~ $4.0 billion of outstanding ~~debt~~aggregate principal indebtedness at December 31, ~~2017.~~2019. At December 31, ~~2017,~~2019, commitments from our bank group were $2.0 billion, all of which $~~1.7~~ ~~billion~~ was ~~unused commitments.~~

unused. We continue to review our existing indebtedness, and we may seek to repay, refinance, repurchase, redeem, exchange or otherwise terminate our indebtedness. If we do seek to refinance our existing indebtedness, there can be no guarantee that we would be able to execute the refinancing on favorable terms or at all.

As a result of our indebtedness, we use a portion of our cash flow to pay interest, which reduces the amount we have available to fund our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Our indebtedness under our ~~credit facility~~Credit Facility is at a variable interest rate, and so a rise in interest rates will generate greater interest ~~expense~~expense. Financial regulators are working to transition away from LIBOR as a reference rate for financial contracts by the end of 2021 and to develop benchmarks to replace LIBOR. Certain types of borrowings under our Credit Facility are derived from the LIBOR reference rate. Our Credit Facility agreement includes general provisions governing the establishment of an alternate rate of interest to the ~~extent we do not have applicable~~LIBOR-based rate that gives consideration to the then prevailing market convention for determining a rate of interest for comparable syndicated loans. At this time, the impact on the Company's borrowing costs, if any, under an alternative reference rate ~~fluctuation hedges. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.~~

scenario is uncertain.

We may incur substantially more debt in the future. Our ~~credit facility~~Credit Facility and the indentures governing our senior notes contain restrictions on our incurrence of additional indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness under the indentures.

Any increase in our level of indebtedness could have adverse effects on our financial condition and results of operations, ~~including~~ including:

imposing additional cash requirements on us in order to support interest payments, which reduces the amount we have available to fund our operations and other business activities;

increasing the risk that we may default on our debt obligations;

increasing our vulnerability to adverse changes in general economic and industry conditions, economic downturns and adverse developments in our business;

limiting our ability to sell assets, engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other ~~purposes. If~~purposes;

limiting our flexibility in planning for or reacting to changes in our business and the industry in which we ~~incur additional debt, the related risks that we now face could intensify. A higher level of indebtedness also increases the risk that we may default on~~operate; and

increasing our ~~debt obligations.~~ exposure to a rise in interest rates, which will generate greater interest expense.

Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance, which is affected by general economic conditions and financial, business and other factors, many of which are ~~beyond~~out of our control.

If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets or sell additional equity on terms that we may not find attractive if it may be done at all. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest, if any, on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the agreements governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default:

the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest;

the lenders under our ~~credit facility~~Credit Facility could elect to terminate their commitments thereunder and cease making further loans; and

we could be forced into bankruptcy or liquidation.

If our operating performance declines, we may in the future need to obtain waivers under our ~~credit facility~~Credit Facility to avoid being in default. If we breach our covenants under our ~~credit facility~~Credit Facility and ~~seek a waiver, we may not be able to~~cannot obtain a waiver from the required ~~lenders. If this occurs,~~lenders, we would be in default under our ~~credit facility,~~Credit Facility, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.

A downgrade in our credit rating could negatively impact our cost of and ability to access capital.

We receive debt credit ratings from S&P Global Ratings (“S&P”), Moody’s Investors Service, Inc. (“Moody’s”) and Fitch Ratings (“Fitch”), which are subject to regular reviews. ~~In August 2017, our long-term debt was assigned a first-time investment grade rating by Fitch, and our rating by S&P was raised to an investment grade rating.~~ In determining our ratings, the agencies 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.

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. In September 2017, we elected to enter into an Investment Grade Period under our ~~credit facility,~~Credit Facility, as defined in Note 10 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data,” which had the effect of releasing all collateral formerly securing ~~the credit facility.~~our Credit Facility. 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 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 adverse effect on our business, financial condition and results of operations.

As of the filing of this report, no additional changes in our credit ratings have occurred; however, we cannot be assured that our credit ratings will not be downgraded in the future.

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.

We may incur significant delays, costs and liabilities as a result of environmental, occupational health and safety requirements applicable to our oil and natural gas exploration, development and production, and related saltwater disposal ~~activities.~~activities or the activities

of our suppliers of critical materials and services. These delays, costs and liabilities could arise under a wide range of federal, state and local laws and regulations relating to protection of the environment (including wildlife and natural resources), occupational health and safety, including regulations and enforcement policies that have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations.

Strict as well as joint and several liability for a variety of environmental costs may be imposed on us under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Costs stemming from environmental remediation obligations could be significant and adversely affect our financial condition and results of operations. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. No assurance can be given that continued compliance with existing or future environmental laws and regulations will not result in a curtailment of production or processing activities or result in a material increase in the costs of production, development, exploration or processing operations. If we are not able to recover the resulting costs through insurance or increased revenues, our production, revenues and results of operations could be adversely affected.

Our producing properties are concentrated in the Permian Basin of ~~southeast~~West Texas and Southeast New Mexico, ~~and west Texas,~~ making us vulnerable to risks associated with operating in one major geographic area. In addition, substantially all of our proved reserves are attributable to this area.

Our producing properties are geographically concentrated in the Permian Basin of ~~southeast~~West Texas and Southeast New ~~Mexico and west Texas.~~Mexico. At December 31, ~~2017,~~2019, substantially all of our total estimated proved reserves were attributable to properties located in this area. As a result of this geographic concentration, we are exposed to the impact of regional supply and demand ~~factors,~~factors; delays or interruptions of production from wells in this area caused by governmental ~~regulation,~~regulation; processing or transportation capacity constraints, including potential pipeline capacity constraints in the Permian Basin; market ~~limitations,~~limitations; severe weather ~~events,~~events; water shortages or other drought related ~~conditions~~conditions; or interruption of the processing or transportation of oil ~~natural gas~~ or natural ~~gas liquids.~~

gas.

In addition to the geographic concentration of our producing properties described above, at December 31, ~~2017,~~2019, approximately: (i) 3555 percent of our proved reserves were attributable to the ~~Northern~~ Delaware Basin ~~core area~~ that primarily targets the Avalon, ~~shale and~~ Bone Spring and Wolfcamp formations; ~~(ii) 15 percent of our proved reserves were attributable to the Southern Delaware Basin core area that primarily targets the Bone Spring~~ and ~~Wolfcamp formations;~~ (iii) 3245 percent of our proved reserves were attributable to the Midland Basin ~~core area~~ that primarily targets the Spraberry and Wolfcamp and Spraberry formations; and (iv) 18 percent of our proved reserves were attributable to the New Mexico Shelf core area that primarily targets the Yeso formation, which includes both the Paddock and Blinebry intervals underlying our oil and natural gas properties located in southeast New Mexico.formations. This concentration of assets exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

We periodically assess our unproved oil and natural gas properties for impairment and could be required to recognize non-cash charges to earnings of future periods.

At December 31, ~~2017,~~2019, we carried unproved property costs of ~~$2.7~~$5.9 billion. GAAP requires periodic assessment of these costs on a project-by-project basis. Our assessment ~~considers~~ considers:

future drilling and exploration ~~plans,~~ plans;

results of exploration ~~activities,~~ activities;

commodity price ~~outlooks,~~ outlooks;

planned future ~~sales,~~ sales; and

expiration of all or a portion of the projects, contracts and permits relevant to such projects.

Based on our assessments, we may determine that we are unable to fully recover the cost invested in each project, and we will recognize non-cash charges to earnings in future periods if such determination is made.

For the years ended December 31, 2019 and 2018, we recorded $147 million and $35 million, respectively, of leasehold abandonments primarily related to expiring acreage and acreage where we had no future plans to drill, which is included in exploration and abandonments expense in our consolidated statements of operations.

We periodically evaluate our goodwill for impairment and could be required to recognize non-cash charges to earnings of future periods.

At December 31, 2019, we had goodwill of approximately $1.9 billion. We assess goodwill for impairment as of July 1 of each year or whenever circumstances indicate that the carrying value of our business may be impaired. If the book value of our reporting unit exceeds the estimated fair value of the reporting unit, an impairment charge will occur, which would negatively impact our results of operations and net worth. We performed an impairment test at December 31, 2019 due to a decline in our fair value during the second half of 2019 and recorded a $201 million impairment charge. See Note 2 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.

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 our 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 our results of operations in the period incurred. We recorded impairment charges of ~~$1.5 billion and $61~~$890 million in ~~2016 and 2015, respectively.~~2019. We did not incur an impairment charge in 2018 or 2017.

See Note 8 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.

Our commodity price risk management program may cause us to forego additional future profits or result in us making cash payments to our counterparties.

To reduce our exposure to changes in the prices of 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. Commodity price risk management arrangements expose us to the risk of financial loss and may limit our ability to benefit from increases in commodity prices in some circumstances, including the following:

market prices may exceed the prices which we are contracted to receive, resulting in our need to make significant cash payments to our counterparties;

there may be a change in the expected differential between the underlying price in a commodity price risk management agreement and actual prices received; or

the counterparty to a commodity price risk management contract may default on its contractual obligations to us.

Our commodity price risk management activities could have the effect of reducing our net income and the value of our securities. At December 31, ~~2017,~~2019, we had a net derivative liability of ~~approximately $379~~$102 million. An average increase in the commodity price of $5.00 per barrel of oil and $0.50 per MMBtu ~~for~~of natural gas from the commodity price at December 31, ~~2017~~ 2019 would have resulted in an increase in our net liability of approximately $~~327~~ ~~million~~.$451 million. We may continue to incur significant gains or losses in the future from our commodity price risk management activities to the extent market prices increase or decrease and our derivatives contracts remain in place.

Our actual production could differ materially from our forecasts.

From time to time, we provide forecasts of expected quantities of future oil and gas production and other financial and operating results. These forecasts are based on a number of estimates and assumptions. Production forecasts, specifically, are based on assumptions such as:

expectations of production from existing wells and future drilling activity;

the absence of facility or equipment malfunctions;

the absence of adverse weather effects;

expectations of commodity prices, which could experience significant volatility;

expected well costs; and

the assumed effects of regulation by governmental agencies, which could make certain drilling activities or production uneconomical.

Should any of these assumptions prove inaccurate, or should our development plans change, actual production could be materially and adversely affected. Failure to meet operating or financial forecasts and expectations, whether published by us or market participants, could adversely impact the trading price of our common stock.

Our identified inventory of drilling locations and recompletion opportunities are scheduled over several future years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

We have identified and scheduled the drilling of certain locations as an estimation of our future multi-year development activities on our existing acreage. These identified locations represent a significant part of our development and growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including those described elsewhere in these risk ~~factors~~. factors. Because of these and other potential uncertainties, we may never drill the potential locations we have identified or produce oil or natural gas from these or any other potential locations. As such, our actual development activities may materially differ from those presently identified, which could adversely affect our production, reserves, revenues and results of operations.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flow, our ability to raise capital and the value of our securities.

Unless we conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. The value of our securities and our ability to raise capital will be adversely impacted if we are not able to replace our reserves that are depleted by production or replace our declining production with new production. We may not be able to develop, exploit, find or acquire sufficient additional reserves or replace our current and future production.

The Standardized Measure and PV-10 of our estimated reserves are not accurate estimates of the current fair value of our estimated proved oil and natural gas reserves.

Standardized Measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Our non-GAAP financial measure, PV-10, is a similar reporting convention that we have disclosed in this report. Both measures require the use of operating and development costs prevailing as of the date of computation. Consequently, they will not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the 10 percent discount factor, which is required by the rules and regulations of the SEC to be used in calculatingdiscounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our company or the oil and natural gas industry in general. Therefore, Standardized Measure and PV-10 included in this report should not be construed as accurate estimates of the current fair value of our proved reserves.

Our reserve estimates and our computation of future net cash flows at December 31, 2019 are based on SEC pricing of (i) $~~47.79~~ $52.19 per Bbl WTI posted oil price and (ii) $~~2.98~~ $2.58 per MMBtu Henry Hub spot natural gas price, adjusted for location and quality by property. The SEC pricing for reserves as of December 31, 2017 is lower than the NYMEX oil price of $61.68 per Bbl at February 16, 2018 but higher than the NYMEX natural gas price of $2.56 per MMBtu at February 16, 2018. If average oil prices were $5.00 per barrel lower than the average price we used, our PV-10 at December 31, ~~2017~~2019 would have decreased from ~~$8.5~~$10.6 billion to ~~$7.4~~$9.2 billion. If average natural gas prices were $0.50 per MMBtu lower than the average price we used, our PV-10 at December 31, ~~2017~~2019 would have decreased from ~~$8.5~~$10.6 billion to ~~$8.1~~$10.2 billion. Any adjustments to the estimates of proved reserves or decreases in the price of our commodities may decrease the value of our securities.

We may be unable to make attractive acquisitions or successfully integrate acquired companies or assets, and any inability to do so may disrupt our business and hinder our ability to grow.

One aspect of our business strategy calls for acquisitions of businesses or assets that complement or expand our current business. We may not be able to identify attractive acquisition opportunities, including acreage trades. Even if we do identify attractive candidates, pursuing such acquisitions may be distracting to management and costly to the Company. We may not be able to complete the acquisition of them or do so on commercially acceptable terms.

In addition, our ~~credit facility~~Credit Facility and the indentures governing our senior notes impose certain limitations on our ability to enter into mergers or business combination transactions. Our ~~credit facility~~Credit Facility and the indentures governing our senior notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses or assets. If we desire to engage in an acquisition that is otherwise prohibited by our ~~credit facility~~Credit Facility or the indentures governing our senior notes, we will be required to seek the consent of our lenders or the holders of the senior notes in accordance with the requirements of ~~the credit facility~~our Credit Facility or the indentures, which consent may be withheld by the lenders under our ~~credit facility~~Credit Facility or such holders of senior notes at their sole discretion.

If we acquire another business or assets, we could have difficulty integrating its operations, systems, management and other personnel and technology with our own. These difficulties could disrupt our ongoing business, distract our management and employees, increase our expenses and adversely affect our results of operations. In addition, we may incur additional debt or issue additional equity to pay for any future acquisitions, subject to the limitations described above.

Any acquisition we complete is subject to substantial risks that could adversely affect our business, including the risk that our acquisitions may prove to be worth less than what we paid because of uncertainties in evaluating recoverable reserves and could expose us to potentially significant liabilities.

We obtained a significant portion of our current reserve base through acquisitions of producing properties and undeveloped acreage. We expect that acquisitions, including acreage trades, will continue to contribute to our future growth. In connection with these and potential future acquisitions, we are often only able to perform limited due diligence. The success of any acquisition involves potential risks, including among other things:

the inability to estimate accurately the costs to develop the reserves, recoverable volumes of reserves, rates of future production and future net cash flows attainable from the reserves;

the assumption of unknown liabilities, including environmental liabilities, and losses or costs for which we are not indemnified or for which the indemnity we receive is inadequate;

the effect on our liquidity or financial leverage of using available cash or debt to finance acquisitions;

the diversion of management’s attention from other business concerns; and

·an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets.

Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future commodity prices, operating costs and potential environmental, regulatory and other liabilities. Such assessments are inexact, and we cannot make these assessments with a high degree of accuracy. In connection with our assessments, we perform a review of the acquired properties that we believe to be generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise.

There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We are sometimes able to obtain contractual indemnification for preclosing liabilities, including environmental liabilities, but we generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. In addition, even when we are able to obtain such indemnification from the sellers, these indemnification obligations usually expire over time and expose us to potential unindemnified liabilities, which could materially adversely affect our production, revenues and results of operations.

Shortages of oilfield equipment, services and qualified personnel could delay our drilling program and increase the prices we pay to obtain such equipment, services and personnel.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with commodity prices, causing periodic labor shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher commodity prices generally stimulate demand and result in increased prices for drilling and workover rigs, crews and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be. These types of shortages or price increases would decrease our profit margin, cash flow and operating results, or restrict our ability to drill the wells and conduct the operations which we currently have planned and budgeted or which we may plan in the future.

Our exploration and development drilling may not result in commercially productive reserves.

Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. New wells that we drill may not be productive, or we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be produced economically. Drilling for oil and natural gas often involves unprofitable results, not only from dry holes but also from wells that are productive but do not produce sufficient net reserves to return a profit at then realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. ~~Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:~~

·~~unexpected drilling conditions;~~

·~~title problems;~~

·risks associated with drilling horizontal wells and extended lateral lengths, such as deviating from the desired drilling zone or not running casing or tools consistently through the wellbore, particularly as lateral lengths get longer;

·~~pressure or irregularities in formations;~~

·~~equipment failures or accidents;~~

·~~fracture stimulation accidents or failures;~~

·~~adverse weather conditions;~~

·~~compliance with environmental and other governmental or contractual requirements; and~~

·~~increases in the cost of, or shortages or delays in the availability of, electricity, water, supplies, materials, drilling or workover rigs, equipment and services.~~

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. In addition, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities,including well stimulation and completion activities such as hydraulic fracturing, are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

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

·~~abnormally pressured or structured formations;~~

mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

blowouts, cratering, fires, explosions and ruptures of pipelines;

personal injuries and death; and

natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

damage to and destruction of property and equipment;

damage to natural resources due to underground migration of hydraulic fracturing fluids;

pollution and other environmental damage, including spillage or mishandling of recovered hydraulic fracturing fluids;

regulatory investigations and penalties;

loss of well location, acreage, expected production and related reserves;

suspension or delay of our operations;

substantial liability claims; and

repair and remediation costs.

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable, and we do not insure for business interruption of the loss of a well. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse effect on our production, revenues and results of operations.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Some of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, those companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost and other challenges to attract and retain qualified personnel may increase substantially in the future. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. Our failure to acquire properties, market oil and natural gas, ~~and~~ secure trained personnel and adequately compensate personnel could have a material adverse effect on our production, revenues and results of operations.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas processing or transportation arrangements may hinder our access to oil ~~natural gas~~ and natural gas ~~liquid~~ markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil ~~natural gas~~ and natural gas, ~~liquids,~~ the proximity of reserves to pipelines and ~~terminal~~storage facilities, gathering systems and other transportation, processing, fractionation, refining and export facilities, competition for such facilities and the inability of such facilities to gather, transport or process our production due to shutdowns or curtailments arising from mechanical, operational or weather related matters, including hurricanes and other severe weather conditions. Our ability to market our production depends in substantial part on the availability and capacity of gathering, storage and transportation systems, pipelines and processing facilities owned and operated by third parties. Throughout 2018 and 2019, concerns emerged that Permian oil and natural gas supply would exceed pipeline capacity. Our ability to market our production may be impacted if such constraints continue or become worse in the future. Our failure to obtain such services on acceptable terms or the failure of counterparties to perform under certain of our transportation or marketing arrangements could have a material adverse effect on our business, financial condition and results of operations. We may be required to shut in or otherwise curtail

production from wells due to lack of a market or inadequacy or unavailability of oil ~~natural gas liquid~~ or natural gas pipeline or gathering, storage, transportation or processing ~~capacity.~~capacity and fractionation, refining or export facilities. If that were to occur, then we would be unable to realize revenue from those wells until suitable arrangements were made to market our production.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, timing, manner or feasibility of conducting our operations or that may subject us to fines or penalties for any failure to comply.

Our oil and natural gas exploration, development and production, and related saltwater disposal operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, local and governmental authorities. We may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations. If we fail to comply with the existing laws and regulations, we may incur additional costs, including fines and penalties, in order to come back into compliance. In addition, our costs of compliance may increase or our operations may be otherwise adversely affected if existing laws and regulations are revised or reinterpreted or if the government agencies responsible for enforcing certain existing laws and regulations applicable to us change their priorities or policies, or if new laws and regulations become applicable to our operations. These and other costs could have a material adverse effect on our production, revenues and results of operations.

In addition, certain candidates for the 2020 presidential election have espoused as part of their overall campaign platform support for climate change regulation and bans on hydraulic fracturing that could materially impact our business. Approximately 20 percent of our acreage was located on federal lands at December 31, 2019. We cannot be certain of the impact of any new legislation at the state or federal level, but it could harm our business, operating results and financial condition. In addition, speculation regarding potential changes in the regulatory environment creates uncertainties that could lead to increased volatility in the market price of our common stock in the short term.

The ~~adoption~~implementation of derivatives legislation adopted by Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us, which participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), became law on July 21, 2010 and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when this will be accomplished.

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents; however, this initial position limits rule was vacated by the U.S. District Court for the District of Columbia in September 2012. The CFTC has subsequently issued proposals for new rules that would place position limits on certain core futures contracts and equivalent swap contracts for or linked to certain physical commodities, subject to certain exceptions for bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps subject to mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If our swaps do not qualify for the ~~commercial~~ end-user exception from mandatory clearing, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or our ability to hedge may be impacted. The ultimate effect of the rules and any additional regulations on our business is uncertain at this time.

In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. ~~Although~~While we ~~expect to qualify~~are exempt from such requirements for the ~~end-user exception from such~~mandatory exchange of margin ~~requirements~~ for uncleared swaps, ~~entered into to hedge our commercial risks,~~ the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. ~~If any of our swaps do~~Further, if we did not qualify for ~~the commercial end-user exception, the posting of~~an exemption and were required to post collateral for our swaps, it could reduce our liquidity and cash available for capital expenditures and our ability to manage commodity price volatility and the volatility in cash flows.

The full impact of the Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. When fully implemented, the Act and any new regulations could increase the operational and transactional cost of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize and restructure our existing derivatives contracts, impact commodity prices and affect the number and/or creditworthiness of available counterparties. If we reduce our use of derivatives as a result of the Act and regulations implementing the Act, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

The loss of our chief executive officer or other key personnel could negatively impact our ability to execute our business strategy.

We depend, and will continue to depend in the foreseeable future, on the services of our chief executive officer, Timothy A. Leach, and other officers and key employees who have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production, and developing and executing acquisition, financing and hedging strategies. Our ability to hire and retain our officers and key employees is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could negatively impact our ability to execute our business strategy.

Because we do not operate and therefore control the development of certain ~~of the~~ properties in which we own interests, we may not be able to produce economic quantities of oil and natural gas in a timely ~~manner~~.

manner.

At December 31, ~~2017,~~2019, approximately 75 percent of our proved reserves were attributable to properties for which we were not the operator. As a result, the success and timing of drilling and development activities on properties operated by others depend upon a number of factors that are beyond our control, including:

the nature and timing of drilling and operational activities controlled by others;

the timing and amount of the operators’ capital expenditures;

the operators’ expertise and financial resources;

the approval of other participants in such properties; and

the selection and application of suitable technology.

If drilling and development activities are not conducted on these properties or are not conducted as we expect, we may be unable to increase our production or offset normal production declines or we will be required to write-off the reserves attributable to such properties, which may adversely affect our production, revenues and results of operations.

We do not control certain of the entities in which we own equity interests.

Certain of the entities in which we own equity interests are managed by their respective governing bodies, which we do not control. As a result, our ability to influence decisions with respect to the operation of such entities’ businesses and distributions from such entities is limited. Such ability varies depending on the amount of control we exercise under the applicable governing agreement, including with respect to cash distributions, capital calls, capital expenditures and the incurrence of additional indebtedness.

A terrorist or cyber attack or armed conflict could harm our business by decreasing our revenues and increasing our costs.

Terrorist activities, anti-terrorist efforts, ~~cyber-attacks~~cyber attacks and other armed ~~conflict~~conflicts involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our production and causing a reduction in our revenue. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of oil and natural gas production are destroyed or damaged. Additionally, as an oil and natural gas producer, we constantly face various cybersecurity threats, including threats to gain unauthorized access to sensitive information or to render data or systems unusable, and there can be no assurance that our implementation of various procedures and controls to monitor and mitigate security threats will be sufficient to prevent security breaches from occurring. Costs for insurance, recovery, remediation, potential litigation and other security measures may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Our reliance on information technology, including those hosted by third parties, exposes us to cyber security risks that could affect our business, financial condition or reputation and increase compliance challenges.

We rely extensively on information technology systems, including ~~Internet~~internet sites, computer software, data hosting facilities and other hardware and platforms, some of which are hosted by third parties, to assist in conducting our business. Our information technology systems, as well as those of third parties we use in our operations, may be vulnerable to a variety of 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.

These cybersecurity threat actors, whether internal or external to us, are becoming more sophisticated and coordinated in their attempts to access the company’s information technology systems and data, including the information technology systems of cloud providers and other third parties with whom the company conducts business.

Although we have implemented information technology controls and systems that are designed to protect information and mitigate the risk of data loss and other cybersecurity risks, such measures cannot entirely eliminate cybersecurity threats, and the enhanced controls we have installed may be breached. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations which may include drilling, completion, production and corporate functions. A cyber attack involving our information systems and related infrastructure, or that of our business associates, could negatively impact our operations in a variety of ways, including, but not limited to, the following:

Unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and natural gas resources;

Data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;

Data corruption or operational disruptions of production-related infrastructure could result in a loss of production, or accidental discharge;

A cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects;

A cyber attack on ~~third party~~third-party gathering, pipeline, or rail transportation systems could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues;

·A cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;

A cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for our production, lower natural gas prices, and reduced revenues;

A cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;

A cyber attack on our automated and surveillance systems could cause a loss in production and potential environmental hazards;

A cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;

A deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties; and

A cyber attack resulting in the loss or disclosure of, or damage to, our or any of our customer’s, supplier’s or ~~supplier’s~~landowner’s data or confidential information could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.

All of the above could negatively impact our operational and financial results. Additionally, certain cyber incidents, such as surveillance, may remain undetected for an extended period. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cyber attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.

Risks Related to Our Common Stock

Our certificate of incorporation, our bylaws and Delaware law contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation, our bylaws and Delaware law could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

the organization of our board of directors as a classified board, which allows no more than approximately one-third of our directors to be elected each year;

stockholders cannot remove directors from our board of directors except for cause and then only by the holders of not less than 66 2/3 percent of the voting power of all outstanding voting stock;

the prohibition of stockholder action by written consent; and

limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

~~Because we have not historically and do not have immediate plans to pay dividends on our common stock, investors are currently limited to stock appreciation for a return on their investment in us.~~

~~We do not have plans to pay cash dividends on our common stock in the near future. We currently intend to retain future earnings to fund the development and growth of our business. Any~~

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

While the Company declared a quarterly dividend of $0.125 per share for each quarter in 2019 and intends to continue to pay a dividend in the future, the payment and amount of future dividend payments, if any, are subject to declaration by our board of directors. Such payments will depend on ~~among other things, our earnings,~~various factors, including actual results of operations, liquidity and financial condition, ~~capital requirements, level of indebtedness, statutory and contractual~~net cash provided by operating activities, restrictions ~~applying to the payment of dividends~~imposed by applicable law, our taxable income, our operating expenses and other ~~considerations that~~factors our board of directors deems relevant. Covenants contained in our ~~credit facility~~Credit Agreement and the indentures governing our senior notes could limit the payment of ~~dividends; however, at December 31, 2017,~~dividends. The Company is under ~~our covenants we could pay dividends in excess of $1 billion. Investors must rely~~no obligation to make dividend payments on ~~sales of their~~our common stock ~~after price appreciation, which~~and may ~~never occur, as~~cease such payments at any time in the ~~only way to realize an immediate return on their investment.~~

future.

The availability of shares for sale in the future could reduce the market price of our common stock.

In the future, we may ~~issue securities to raise cash for acquisitions. We may also~~ acquire interests in other companies by using a combination of cash and our common stock or just our common stock. We may also issue securities to raise cash for acquisitions. We may also issue securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our ~~company,~~Company, reduce our earnings per share and have an adverse impact on the price of our common stock.

In addition, sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. This could also impair our ability to raise additional capital through the sale of our securities.

We cannot guarantee that our recently announced share repurchase program will be fully consummated or that such program will enhance the long-term value of our common stock.

In September 2019, we announced that our board of directors authorized the initiation of a $1.5 billion share repurchase program. We funded the 2019 repurchases primarily with proceeds from our New Mexico Shelf divestiture, which closed in November 2019. The Company is under no obligation to repurchase any specific dollar amount of common stock, and the repurchase program may be extended, suspended or discontinued at any time by our board of directors. As such, we cannot guarantee that this program will be fully consummated, or that such program will enhance the long-term value of our common stock. The extent to which we repurchase our common stock and the timing and funding of such repurchases are dependent upon a variety of factors, including market conditions, regulatory requirements and other corporate considerations, as determined by our management and board of directors. As of December 31, 2019, the Company had repurchased and retired 3,300,370 shares under the program at an aggregate cost of $250 million.

Item 1B. Unresolved Staff Comments

There are no unresolved staff comments.

Item 2. Properties

Our Oil and Natural Gas Reserves

The estimates of our proved reserves at December 31, ~~2017,~~2019, all of which were located in the United States, were based on evaluations prepared by the independent petroleum engineering firms of Cawley, Gillespie & Associates, Inc. (“CGA”) and Netherland, Sewell & Associates, Inc. (“NSAI”) (collectively, our “external engineers”). Reserves were estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (the “FASB”).

Internal controls.Our proved reserves are estimated at the property level by external engineers and compiled for reporting purposes by our corporate reservoir engineering staff. We maintain our internal evaluations of our reserves in a secure reserve engineering database. The corporate reservoir engineering staff interact with our internal staff of petroleum engineers, geoscience professionals and land professionals in each of our operating areas and with accounting and marketing employees to obtain the necessary data for the reserves estimation process. Reserves are reviewed and approved internally by members of our senior management and the health, safety, environment and reserves committee, a committee of our ~~Board~~board of ~~Directors.~~

directors.

Our internal professional staff works closely with our external engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their preparation of our reserves.

Qualifications of responsible technical persons

~~J. Steve Guthrie~~ ~~has been~~

Keith Corbett is our Senior Vice President of ~~Business~~Corporate Engineering and Planning. In this role, Mr. Corbett is responsible for corporate reservoir engineering and strategic planning. Mr. Corbett joined the Company in 2005 as a Reservoir Engineer and has served in several Asset Manager roles and as an Operations ~~and Engineering since November 2013. Mr. Guthrie previously served~~Supervisor before he was appointed as ~~the~~ Vice President of Texas ~~the Texas Asset Manager and Corporate Engineering Manager.~~(later, Vice President of Midland Basin) in 2015. Prior to joining ~~the Company,~~Concho, Mr. ~~Guthrie was employed by Moriah Resources as Business Development Manager, by Henry Petroleum in various~~Corbett held drilling, reservoir and production engineering positions at Pennzoil (later Devon Energy) and ~~operations capacities and by Exxon in several engineering and operations positions.~~Stallion Energy. Mr. ~~Guthrie~~Corbett is a graduate of Texas ~~Tech~~A&M University with a Bachelor of Science degree in Petroleum Engineering.

Rick Mortonjoined the Company in 2011 and currently serves as the Corporate Engineering ~~Manager.~~Director. Prior to joining the Company, Mr. Morton served as Division Acquisition Coordinator for EOG Resources, Inc. Mr. Morton was also previously employed by Southwest Royalties, Inc. as Vice President and Exploitation Manager and by Merit Energy Company in various engineering positions. Mr. Morton began his career in 1983 with Arco Oil and Gas Company as an Operations/Analytical Engineer before moving to a Production Supervisor position. He is a graduate of Texas A&M University with a Bachelor of Science degree in Petroleum Engineering.

��

CGA.Approximately 5355 percent of the proved reserves estimates shown herein at December 31, ~~2017~~2019 have been independently prepared by CGA, a leader of petroleum property analysis for industry and financial institutions. CGA was founded in 1960 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January ~~19, 2018,~~27, 2020, filed as an exhibit to this Annual Report on Form 10-K, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 3032 years of practical experience in petroleum engineering, with over 2830 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

NSAI.Approximately 4745 percent of the proved reserve estimates shown herein at December 31, ~~2017~~2019 have been independently prepared by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI letter dated January ~~24, 2018,~~23, 2020, filed as an exhibit to this Annual Report on Form 10-K, was Mr. Craig H. Adams. Mr. Adams, a Licensed Professional Engineer in the State of Texas (License No. 68137), has been practicing consulting petroleum engineering at NSAI since 1997 and has over 1112 years of prior industry experience. He graduated from Texas Tech University in 1985 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Adams meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

Our oil and natural gas reserves.The following table sets forth our estimated proved oil and natural gas reserves at December 31, ~~2017.~~ 2019.Our reserve estimates and our ~~computation~~calculation of future net cash flows are based on SEC pricing of (i) ~~$47.79~~$52.19 per Bbl WTI posted oil price and ~~$2.98~~$2.58 per MMBtu Henry Hub spot natural gas price, adjusted for location and quality differentials by property.

Oil

Natural Gas

Total

(MMBbl)

(Bcf)

(MMBoe)
Core Operating Areas:

Northern Delaware Basin

149

878

295

Southern Delaware Basin

92

214

128

Midland Basin

175

546

266

New Mexico Shelf

84

404

151
Other

-

1

-

Total

500

2,043

840



	Oil (MMBbl)	Natural Gas (Bcf)	Total (MMBoe)
Operating Areas:
Delaware Basin	339	1,300	556
Midland Basin	280	998	446
Total	619	2,298	1,002

Thefollowing table sets forth our estimated proved reserves by category at December 31, ~~2017:~~

2019:

Oil

Natural Gas

Total

Percent of

(MMBbl)

(Bcf)

(MMBoe)

Total

Proved developed producing

324

1,481

571

68%
Proved developed non-producing

12

31

17

2%
Proved undeveloped

164

531

252

30%

Total proved

500

2,043

840

100%

Total proved developed

336

1,512

588

70%

Oil
(MMBbl)

Natural Gas
(Bcf)

Total
(MMBoe)

Percent of
Total
Proved developed producing 432
1,779
728
72 %
Proved developed non-producing 10
39
17
2 %
Proved undeveloped 177
480
257
26 %
Total proved 619
2,298
1,002
100 %

Total proved developed 442
1,818
745
74 %

Changes to proved reserves.The following table sets forth the changes in our proved reserve volumes by area during the year ended December 31, ~~2017~~2019 (in MMBoe):

Purchases of

Sales of

Revisions of

Extensions and

Minerals-in-

Minerals-in-

Previous

Production

Discoveries

Place

Place

Estimates

Core Operating Areas:

Northern Delaware Basin

(33)

63

15

-

16

Southern Delaware Basin

(10)

29

4

-

(4)

Midland Basin

(16)

77

14

(4)

2

New Mexico Shelf

(11)

5

1

-

(28)

Total

(70)

174

34

(4)

(14)

Production
Extensions and
Discoveries

Purchases of
Minerals-in-
Place

Sales of
Minerals-in-
Place

Revisions of
Previous
Estimates
Operating Areas:
Delaware Basin (79 ) 111
6
(102 ) (54 )
Midland Basin (42 ) 66
3
(3 ) (91 )
Total (121 ) 177
9
(105 ) (145 )

Extensions and ~~discoveries~~. discoveries.Extensions and discoveries of approximately ~~174~~177 MMBoe ~~are~~were primarily the result of our ~~continued success from our extension and infill~~ horizontal drilling programs in our ~~core~~ operating areas. Proved developed reserves increased approximately 82106 MMBoe due to our ~~exploratory~~ drilling activity in ~~2017. Based~~2019, and based upon this activity, we added approximately 9271 MMBoe of new proved undeveloped ~~locations were added.~~

reserves.

Purchases and sales of ~~minerals-in-place~~. minerals-in-place.Our purchases of minerals-in-place ~~are composed~~were primarily the result of ~~approximately 11 MMBoe from the July 2017 Midland Basin acquisition, 8 MMBoe from the January 2017 Northern Delaware Basin acquisition~~certain acquisitions and ~~15 MMBoe from various other acquisitions throughout the year.~~nonmonetary transactions during 2019. Our sales of 105 MMBoe of minerals-in-place ~~are composed~~were the result of ~~approximately 4 MMBoe from~~ various divestitures ~~throughout~~and nonmonetary transactions during 2019, primarily the ~~year.~~

New Mexico Shelf divestiture. See Note 5 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.

Revisions of previous ~~estimates~~. estimates.Revisions of previous estimates ~~are~~were composed of (i) 6128 MMBoe of negative revisions primarily due to the reclassification of proved undeveloped reserves ~~reclassified~~ to unproved as they were no longer expected to be developed within five years of the date of their initial recognition, (ii) 82 MMBoe of net negative performance and other revisions and (iii) 35 MMBoe of negative price revisions. Our proved reserves ~~because they~~at December 31, 2019 were determined using the SEC prices of $52.19 per Bbl of oil for WTI and $2.58 per MMBtu of natural gas for Henry Hub spot, as compared to corresponding prices of $62.04 per Bbl of oil and $3.10 per MMBtu of natural gas at December 31, 2018. Negative performance revisions were primarily the result of our recent capital programs that included projects testing tighter well spacing. We have modified our development approach to prioritize wider spacing between wells in order to maximize well performance and program economics.

Proved undeveloped reserves. At December 31, 2019, we had approximately 257MMBoe of proved undeveloped reserves as compared to 363 MMBoe at December 31, 2018.

The following table summarizes the changes in our proved undeveloped reserves during 2019 (in MMBoe):



At December 31, 2018	363
Extensions and discoveries	71
Purchases of minerals-in-place	3
Sales of minerals-in-place	(4	)
Revisions of previous estimates	(83	)
Conversion to proved developed reserves	(93	)
At December 31, 2019	257

Extensions and discoveries.Extensions and discoveries of approximately 71 MMBoe are primarily the result of new proved undeveloped locations that were added as a result of our drilling program during 2019.

Revisions of previous estimates.Negative revisions of previous estimates of approximately 83 MMBoe are primarily attributable to (i) 48 MMBoe of negative revisions primarily due to revisions in our spacing assumptions, (ii) 28 MMBoe of negative revisions for properties that are no longer expected to be developed within five years of the date of their initial recognition ~~as required by SEC rules due to a shift in~~and were removed from our ~~capital program to generally focus more on large-scale development projects in certain areas, (ii) 29~~current drilling plans, and (iii) 7 MMBoe of ~~positive~~other negative revisions including negative price revisions. Negative performance revisions ~~and (iii) 18 MMBoe of positive technical and performance revisions. Our proved reserves at December 31, 2017~~ were ~~determined using the SEC~~

prices of $47.79 per Bbl of oil for WTI and $2.98 per MMBtu of natural gas for Henry Hub spot, compared to corresponding prices of $39.25 per Bbl of oil and $2.48 per MMBtu of natural gas at December 31, 2016.

~~Proved undeveloped reserves.~~ ~~At December 31, 2017, we had approximately 252MMBoe of proved undeveloped reserves as compared to 254 MMBoe at December 31, 2016.~~

~~The following table summarizes the changes in our proved undeveloped reserves during 2017 (in MMBoe):~~

~~At December 31, 2016~~

~~254~~

~~Extensions and discoveries~~

~~Purchases of minerals-in-place~~

~~Revisions of previous estimates~~

~~(39)~~

~~Conversion to proved developed reserves~~

~~(66)~~

~~At December 31, 2017~~

~~252~~

~~Extensions and discoveries~~. ~~Extensions and discoveries of approximately 92 MMBoe are~~ primarily the ~~result~~results of ~~new proved undeveloped locations~~our recent capital programs that ~~were added.~~

~~Revisions of previous estimates.~~ ~~Net negative revisions of previous estimates of approximately 39 MMBoe are primarily attributable~~included projects testing tighter well spacing. We have modified our development approach to ~~(i) 61 MMBoe of negative revisions due~~prioritize wider spacing between wells in order to proved undeveloped reserves reclassified to unproved reserves because they are no longer expected to be developed within five years of the date of their initial recognition due to a shift in our capital program to generally focus more on large-scale development projects in certain areas, (ii) 6 MMBoe of positive price revisions and (iii) 16 MMBoe of net positivemaximize well performance and ~~miscellaneous revisions.~~

program economics.

Conversion to proved developed reserves.The following table sets forth proved undeveloped reserves converted to proved developed reserves and the associated investment required to convert proved undeveloped reserves to proved developed reserves during the year ended December 31, ~~2017:~~

2019:

Proved Undeveloped Reserves Converted to

Investment in Conversion of Proved Undeveloped
Proved Developed Reserves

Reserves to Proved Developed Reserves

Oil (MMBbl)

Natural Gas (Bcf)

Total (MMBoe)

(in millions)

43

141

66

$
619
(a)

~~(a)Of this amount, approximately $79 million was spent in 2017 on proved undeveloped reserves that were not converted to proved developed reserves by December 31, 2017.~~



Proved Undeveloped Reserves Converted to Proved Developed Reserves			Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
Oil (MMBbl)	Natural Gas (Bcf)	Total (MMBoe)		(in millions)
63	178	93		$	1,086	(a)


(a)	Of this amount, approximately $100 million was spent in 2019 on proved undeveloped reserves that were not converted to proved developed reserves by December 31, 2019.

~~The following table sets forth the estimated timing and cash flows of developing our proved undeveloped reserves at December 31, 2017 (dollars in millions):~~

Future

Future

Future

Future

Years Ended

Production

Cash

Production

Development

Future Net
December 31, (a)

(MMBoe)

Inflows (b)

Costs

Costs

Cash Flows

2018

9

$
346

$
(51)

$
(709)

$
(415)
2019

20

796

(120)

(623)

53
2020

26

987

(158)

(611)

219
2021

25

918

(153)

(228)

537
2022

20

728

(131)

(85)

512
Thereafter

152

5,656

(1,403)

-

4,253

Total

252

$
9,431

$
(2,016)

$
(2,256)

$
5,159

(a)
Beginning in 2018 and thereafter, the production and cash flows represent the drilling results from the respective year plus the incremental effects from the results of proved undeveloped drilling from previous years.

(b)
Computation is based on SEC pricing of (i) $47.79 per Bbl WTI posted oil price and (ii) $2.98 per MMBtu Henry Hub spot natural gas price, adjusted for location and quality by property.

Historically, our drilling programs were substantially funded from our cash ~~flow~~flows from operations and borrowings from our ~~credit facility.~~Credit Facility. Based on our current expectations ~~over the next five years~~ of our cash flows and drilling programs over the next five years, which includes drilling of proved undeveloped and ~~unproven~~unproved locations, we believe that we can continue to substantially fund our drilling activities from our cash flow and with borrowings from our ~~credit facility,~~Credit Facility, if needed.

Developed and Undeveloped Acreage

The following table presents our total gross and net developed and undeveloped acreage by area at December 31, ~~2017:~~

2019:

Developed Acres (a)

Undeveloped Acres (b)

Total Acres
(in thousands)

Gross

Net

Gross

Net

Gross

Net

Core Operating Areas:

Northern Delaware Basin

194

131

179

128

373

259

Southern Delaware Basin

72

56

74

38

146

94

Midland Basin

187

110

78

44

265

154

New Mexico Shelf

69

45

52

33

121

78

Total

522

342

383

243

905

585

~~(a)Developed acres are acres attributable or assigned to wells producing economic quantities of oil or natural gas and do not include undrilled acreage held by production.~~

~~(b)~~Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.



	Developed Acres (a)		Undeveloped Acres (b)		Total Acres
(in thousands)	Gross	Net	Gross	Net	Gross	Net
Operating Areas:
Delaware Basin	325	220	199	132	524	352
Midland Basin	213	152	72	45	285	197
Total	538	372	271	177	809	549


(a)	Developed acres are acres attributable or assigned to wells producing economic quantities of oil or natural gas and do not include undrilled acreage held by production.


(b)	Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

The following table sets forth the future expiration amounts of our gross and net undeveloped acreage at December 31, ~~2017~~2019 by ~~core~~operating area:

2018

2019

2020

Thereafter

(in thousands)

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Core Operating Areas:

Northern Delaware Basin

3

3

3

3

2

1

9

9

Southern Delaware Basin

15

8

9

5

10

1

-

-

Midland Basin (a)

1

-

-

1

1

-

-

-

New Mexico Shelf

2

-

1

-

2

1

1

1

Total

21

11

13

9

15

3

10

10

(a)
Expiring net acres are greater than gross acres in our Midland Basin core area in 2019 as certain leases contain undivided interests and have multiple net acreage expiration dates within the same tract of land. Expirations of net acres are shown in the year they occur, while the expirations of gross acres are shown in the final year of net acre expiration.



	2020		2021		2022		Thereafter
(in thousands)	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Operating Areas:
Delaware Basin	14	4	8	4	5	3	8	8
Midland Basin	—	—	1	1	2	—	—	—
Total	14	4	9	5	7	3	8	8

At December 31, ~~2017,~~2019, we had approximately ~~68,000~~82,000 gross and ~~47,000~~69,000 net acres subject to a continuous development clause ~~(“CDC”). Acres subject to a CDC typically require the commencement of~~or similar drilling ~~a well within six to twelve months of the completion of the most recent well on the related lease.~~commitments. Historically, we have not experienced material expiration of acres due to non-compliance ~~with a CDC,~~ and we do not anticipate any material expirations during ~~2018.~~

2020 or any future periods.

For summary tables that set forth information with respect to wells drilled and completed for the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015,~~2017, see “Item 1. Business—Drilling Activities.”

Our Production, Prices and Expenses

For a summary table that sets forth information concerning our production and operating data from operations for the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~,2017, see “Item 1. Business—Our Production, Prices and Expenses.”

Productive Wells

For a summary table that sets forth the number of productive oil and natural gas wells on our properties at December 31, ~~2017, 2016~~2019, 2018 and ~~2015,~~2017, see “Item 1. Business—Productive Wells.”

Title to Our Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a more thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect defects affecting those properties, we are typically responsible for curing any such defects at our expense. We generally will not commence drilling operations on a property until we have cured known material title defects on such property. We have reviewed the title to substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on the most significant properties, and depending on the materiality of properties, we may obtain a title opinion or review or update previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens that we believe do not materially interfere with the use or affect our carrying value of the properties.

Item 3. 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 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common stock trades on the NYSE under the symbol “CXO.” ~~The following table shows, for the periods indicated, the high and low sales prices for our common stock, as reported on the NYSE.~~

Price Per Share

High

Low

2016:

First Quarter

$
107.00

$
69.94

Second Quarter

$
130.03

$
95.87

Third Quarter

$
137.83

$
114.33

Fourth Quarter

$
147.55

$
123.88

2017:

First Quarter

$
145.60

$
122.65

Second Quarter

$
136.93

$
112.73

Third Quarter

$
134.03

$
106.73

Fourth Quarter

$
155.05

$
128.86

~~On February 16, 2018, the last sales price of our common stock as reported on the NYSE was $146.52 per share.~~

As of February ~~16, 2018,~~14, 2020, there were ~~1,143~~1,467 holders of record of our common stock.

Dividend Policy

~~We do not have plans to pay cash~~

For information about dividends, on our common stock in the near future. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Covenants contained in our credit facility and the indentures governing our senior notes could limit the payment of dividends; however, at December 31, 2017, under our covenants we could pay dividends in excess of $1 billion. See Note 9 of the Notes to Consolidated Financial Statements included insee “Item 8. Financial Statements and Supplementary ~~Data” for additional information.~~

~~Repurchases~~

Issuer Purchases of Equity ~~Securitie~~s

Securities

The following table sets forth repurchases of our common stock during the three months ended December 31, 2019:



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)
October 1, 2019 - October 31, 2019	1,457	$	64.77	—	$	1.50
November 1, 2019 - November 30, 2019	2,367,490	$	74.41	2,367,243	$	1.30
December 1, 2019 - December 31, 2019	933,904	$	79.15	933,127	$	1.25
Total	3,302,851	$	75.75	3,300,370	$	1.25

(a) Includes 2,481 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 fourth quarter of 2019.

(b) During the fourth quarter of 2019, we repurchased and retired 3,300,370 common shares for $250 million under our $1.5 billion share repurchase ~~activity for each period presented:~~

program that was publicly announced in September 2019. The program does not have a stated expiration date.

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

October 1, 2017 - October 31, 2017

103

$
133.24

-

November 1, 2017 - November 30, 2017

35

$
138.40

-

December 1, 2017 - December 31, 2017

360

$
143.64

-




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

This section presents our selected historical consolidated financial data. The selected historical consolidated financial data presented below is not intended to replace our historical consolidated financial statements. You should read the following data along with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included in this report.

Selected Historical Financial Information

Our results of operations for the periods presented below may not be comparable either from period to period or going ~~forward for~~forward. We have completed numerous acquisitions, dispositions and nonmonetary transactions that impact the ~~following reasons:~~

·comparability of the selected financial data between periods. In addition, and due in ~~March 2015, we issued 6.9 million shares of our common stock in a public offering at $107.49 per share, and we received net proceeds of approximately $742 million;~~

·~~in October 2015, we issued approximately 8.9 million shares of our common stock in a public offering at $92.50 per share, and we received net proceeds of approximately $794 million;~~

·in December 2015, we completed an acreage exchange with Clayton Williams Energy, Inc. that consolidated acres into a concentrated, operated position in the Southern Delaware Basin. We recognized a loss on disposition of assets of approximately $50 million relatedpart to the ~~acreage exchange;~~

·aforementioned factors, the selected financial data between periods was impacted by significant changes 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;~~

·in March 2016, we completed an acquisition of 80 percent of a third-party seller’s interest in certain oil and natural gas properties and related assets in the Southern Delaware Basin. As consideration for the acquisition, we issued to the seller approximately 2.2 million shares of our ~~common stock with an approximate value of $231 million, $146 million in cash and $40 million to carry a portion of the seller’s future development costs in these properties;~~

·in August 2016, we issued approximately 10.4 million shares of our common stock in a public offering at $130.90 per share and received net proceeds of approximately $1.3 billion. We used a portion of the net proceeds to finance part of the cash portion of the purchase price for the Reliance Acquisition and to fund part of the early redemption of our 7.0% unsecured senior notes due 2021 (the “7.0% Notes”) and the remainder for general corporate purposes;

·in September 2016, we redeemed the $600 million outstanding principal amount of the 7.0% Notes at a price equal to 103.5 percent of par. The redemption price included the make-whole premium for the early redemption, as determined in accordance with the indenture governing the 7.0% Notes. We also paid accrued and unpaid interest on the 7.0% Notes through September 19, 2016, the redemption date. We recorded a loss on extinguishment of debt related to the redemption of the 7.0% Notes of approximately $28 million. 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;

·in October 2016, we completed the Reliance Acquisition. As consideration for the acquisition, we paid approximately $1.2 billion in cash and issued to the seller approximately 3.9 million shares of common stock with an approximate value of $0.5 billion;

·in December 2016, we issued $600 million in aggregate principal amount of 4.375% senior notes due 2025 (the “4.375% Notes”) at par, for which we received net proceeds of approximately $592 million. We used the net proceeds from the offering to fund the satisfaction and discharge of our obligations under the indenture of the $600 million outstanding principal amount of our 6.5% unsecured senior notes due 2022 (the “6.5% Notes”) at a price equal to 103.25 percent of par;

·in January and April 2017, we closed on the two-part acquisition of approximately 17,600 net acres in the Northern Delaware Basin. As consideration for the entire acquisition, we 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 our common stock with an approximate carrying value of $291 million;

·in February 2017, we closed on the divestiture of our ownership interest in ACC. We and our joint venture partner entered into separate agreements to sell 100 percent of our respective ownership interests in ACC. After adjustments forcapital structure, including various 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;

equity financing transactions.

·~~in July 2017, we completed an acquisition in the Midland Basin. As consideration for the acquisition, we paid approximately $595 million in cash.~~ ~~Concurrent with the acquisition, we entered into a transaction structured as a reverse like-kind exchange in accordance with Section 1031 of the Internal Revenue Code of 1986; and~~

·in September 2017, we issued $1,800 million in aggregate principal amount of unsecured senior notes, consisting of $1,000 million in aggregate principal amount of 3.75% unsecured senior notes due 2027 (the “3.75% Notes”) and $800 million in aggregate principal amount of 4.875% unsecured senior notes due 2047 (the “4.875% Notes” and, together with the 3.75% Notes, the “2017 Notes”). We used the net proceeds of approximately $1,777 million, together with cash on hand and borrowings under our credit facility, 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 related to the 5.5% Notes of approximately $65 million.

Our financial data below is derived from (i) our audited consolidated financial statements included in this report and (ii) other audited consolidated financial statements of ours not included in this report.

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

2017 (a)

2016 (a) (b)

2015 (a)

2014

2013

Statement of operations data:

Total operating revenues

$
2,586

$
1,635

$
1,804

$
2,660

$
2,320

Total operating costs and expenses

(1,512)

(3,704)

(1,477)

(1,580)

(1,704)
Income (loss) from operations

$
1,074

$
(2,069)

$
327

$
1,080

$
616
Income (loss) from continuing operations, net of tax

$
956

$
(1,462)

$
66

$
538

$
239
Income from discontinued operations, net of tax

-

-

-

-

12
Net income (loss) attributable to common shareholders

$
956

$
(1,462)

$
66

$
538

$
251
Basic earnings per share:

Income (loss) from continuing operations

$
6.44

$
(10.85)

$
0.54

$
4.89

$
2.28

Income from discontinued operations, net of tax

-

-

-

-

0.11

Net income (loss) attributable to common shareholders

$
6.44

$
(10.85)

$
0.54

$
4.89

$
2.39
Diluted earnings per share:

Income (loss) from continuing operations

$
6.41

$
(10.85)

$
0.54

$
4.88

$
2.28

Income from discontinued operations, net of tax

-

-

-

-

0.11

Net income (loss) attributable to common shareholders

$
6.41

$
(10.85)

$
0.54

$
4.88

$
2.39

Other financial data:

Net cash provided by operations

$
1,695

$
1,384

$
1,530

$
1,746

$
1,330

Net cash used in investing activities

$
1,719

$
2,225

$
2,602

$
2,618

$
1,864

Net cash provided by (used in) financing activities

$
(29)

$
665

$
1,301

$
872

$
532

EBITDAX (c)

$
1,893

$
1,633

$
1,713

$
2,033

$
1,686

December 31,
(in millions)

2017 (a)

2016 (a) (b)

2015 (a)

2014

2013

Balance sheet data:

Cash and cash equivalents

$
-

$
53

$
229

$
-

$
-

Property and equipment, net

13,041

11,302

10,976

10,206

8,946

Total assets

13,732

12,119

12,642

11,752

9,508

Long-term debt, including current maturities

2,691

2,741

3,332

3,469

3,577

Stockholders’ equity

8,915

7,623

6,943

5,281

3,758

~~(a)~~See Note 4 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a summary of acquisitions, divestitures and nonmonetary transactions included in our financial data for the selected years.

~~(b)A non-cash impairment charge of approximately $1.5 billion is included in income (loss) from operations for the year ended December 31, 2016.~~

~~(c)~~EBITDAX is defined as net income (loss), plus (1) exploration and abandonments, (2) depreciation, depletion and amortization, (3) accretion of discount on asset retirement obligations, (4) impairments of long-lived assets, (5) non-cash stock-based compensation, (6) (gain) loss on derivatives, (7) net cash receipts from (payments on) derivatives, (8) (gain) loss on disposition of assets, net, (9) interest expense, (10) loss on extinguishment of debt, (11) federal and state income tax expense (benefit) from continuing operations and (12) similar items listed above that are presented in discontinued operations. See “Item 1. Business —Non-GAAP Financial Measures and Reconciliations.”



	Years Ended December 31,
(in millions, except per share amounts)	2019 (a) (b)			2018 (a)			2017 (a)			2016 (b)			2015
Statement of operations data:
Total operating revenues	$	4,592		$	4,151		$	2,586		$	1,635		$	1,804
Total operating costs and expenses	(5,579		)	(1,221		)	(1,515		)	(3,709		)	(1,479		)
Income (loss) from operations	$	(987	)	$	2,930		$	1,071		$	(2,074	)	$	325
Net income (loss)	$	(705	)	$	2,286		$	956		$	(1,462	)	$	66
Earnings per share:
Basic net income (loss)	$	(3.55	)	$	13.28		$	6.44		$	(10.85	)	$	0.54
Diluted net income (loss)	$	(3.55	)	$	13.25		$	6.41		$	(10.85	)	$	0.54
Dividends declared per share	$	0.50		$	—		$	—		$	—		$	—

Other financial data:
Net cash provided by operations	$	2,836		$	2,558		$	1,695		$	1,384		$	1,530
Net cash used in investing activities	$	(1,993	)	$	(2,216	)	$	(1,719	)	$	(2,225	)	$	(2,602	)
Net cash provided by (used in) financing activities	$	(773	)	$	(342	)	$	(29	)	$	665		$	1,301
Adjusted EBITDAX (non-GAAP) (d)	$	3,082		$	2,752		$	1,893		$	1,633		$	1,713

December 31,
(in millions) 2019 (a) (b) 2018 (a) 2017 (a) 2016 (b) (c) 2015 (c)
Balance sheet data:
Cash and cash equivalents $ 70
$ —
$ —
$ 53
$ 229
Property and equipment, net 21,327
22,313
13,041
11,302
10,976
Total assets 24,732
26,294
13,732
12,119
12,642
Long-term debt 3,955
4,194
2,691
2,741
3,332
Stockholders’ equity 17,782
18,768
8,915
7,623
6,943

(a)

See Notes 4 and 5 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a summary of acquisitions, divestitures and nonmonetary transactions included in our financial data for the selected years, and Note 10 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a description of associated debt financing transactions. In addition, see Note 2 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a summary of certain other asset divestitures.


(b)	Impairments of long-lived assets of $890 million and $1.5 billion are included in income (loss) from operations for the years ended December 31, 2019 and December 31, 2016, respectively. In addition, a goodwill impairment charge of $282 million is included in income (loss) from operations for the year ended December 31, 2019.


(c)	During 2016 and 2015, we issued approximately 10.4 million and 15.8 million shares of our common stock, respectively, in public offerings and received net proceeds of approximately $1.3 billion and $1.5 billion, respectively.


(d)	Refer to “Item 1. Business—Non-GAAP Financial Measures and Reconciliations” for a definition and reconciliation of adjusted EBITDAX.

Item 7. 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, as well as the selected historical consolidated financial data included elsewhere in this report.

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” and “Item 1A. Risk Factors” for further details about these statements.

Overview

We are an independent oil and natural gas company engaged in the acquisition, development, exploration and production of oil and natural gas properties. ~~Our core operations~~We are ~~primarily focused~~one of 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 developing our resource base by utilizing ~~extended length lateral drilling, enhanced completion techniques,~~large-scale development projects, which include long-lateral wells and multi-well pad locations, ~~and large-scale development projects~~ throughout our ~~four core~~ operating ~~areas: the Northern Delaware Basin, the Southern Delaware Basin, the Midland Basin and the New Mexico Shelf.~~areas. Oil comprised 6062 percent of our ~~840~~1,002 MMBoe of estimated proved reserves at December 31, ~~2017~~2019 and 6263 percent of our 70121 MMBoe of production for ~~2017.~~2019. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 9293 percent of our proved developed producing reserves and 7975 percent of our ~~8,152~~5,981 gross wells at December 31, ~~2017.~~2019. By controlling operations, we are able to more effectively manage the development strategy as well as the cost and timing of exploration and development of our ~~properties, including the drilling and stimulation methods used.~~

properties.

Financial and Operating Performance

Our financial and operating performance for ~~2017~~2019 included the following highlights:

·~~Net income~~


•	Net loss was $705 million ($(3.55)per diluted share) as compared to net income of $2,286 million ($13.25 per diluted share) in 2018. The decrease was primarily due to:


•	$1,727 millionchange in (gain) loss on derivatives due to a loss on derivatives of $895 million during 2019, as compared to a gain of $832 millionduring 2018;

$~~956~~ 890 million ~~($6.41per diluted share) as compared to a net loss~~ of ~~$1.5billion ($(10.85)~~ ~~per diluted share) in 2016. The increase was primarily due to:~~

•~~no recorded~~ impairments of long-lived assets ~~in 2017, as compared to $1.5 billion in non-cash impairment charges in 2016 primarily attributable to properties in our New Mexico Shelf area;~~

•during 2019;


•	$282 million of impairments of goodwill during 2019;

$~~951~~630 million ~~increase in oil and natural gas revenues as a result of a 28percent increase in production and a 24 percent increase in commodity price realizations per Boe~~ ~~(excluding the effects of derivative activities)~~;

•~~$560 million increase~~decrease in gain on disposition of assets ~~net~~ due to a $170 million net gain during 2019 primarily due to the contribution of ~~approximately $678 million during 2017 primarily attributable to our disposition of ACC,~~certain infrastructure assets in exchange for a cash distribution and an equity ownership interest in the entity in July 2019, partially offset by net losses from certain nonmonetary transactions, as compared to a net gain of ~~approximately $118~~$800 million primarily related to certain acquisitions and divestitures during ~~2016 primarily attributable~~2018, as discussed in Note 5 of the Notes to ~~our Northern Delaware Basin divestiture~~Consolidated Financial Statements included in ~~February 2016~~“Item 8. Financial Statements and Supplementary Data”;

•and

$~~243~~486 million ~~decrease in the loss on derivatives; and~~

•~~$21 million decrease~~increase in depreciation, depletion and amortization expense, primarily due to ~~a decrease~~the increase in production and the increase in the depletion rate per ~~Boe, partially offset by an increase in production;~~

Boe.

partially offset by:

•


•	$441 million increase in oil and natural gas revenues as a result of a 26 percent increase in production, partially offset by a 12 percent decrease in commodity price realizations per Boe(excluding the effects of derivative activities);

$~~801~~205 million increase in other income, primarily due to the gain of $289 million on the sale of our ownership interest in the subsidiary of our equity method investment, Oryx Southern Delaware Holdings, LLC (“Oryx”); and

$757 million change in ~~our~~ income ~~tax provision primarily~~taxes due to ~~favorable impacts of the tax law changes enacted through the TCJA, resulting in~~ a ~~provisional discrete income~~$154 million tax benefit ~~of approximately $398 million. This benefit more than offset the $308~~during 2019, as compared to a $603 million ~~income~~ tax expense ~~on income before taxes~~ during ~~2017 at the federal statutory rate;~~

•$88 million increase in production expense, primarily due to (i) increased production associated with our wells successfully drilled and completed in 2016 and 2017 and (ii) our acquisitions during the fourth quarter of 2016 and during 2017; and

•~~$68 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.~~

·2018.

Average daily sales volumes increased by 2826 percent from ~~150,511~~262,937 Boe per day during ~~2016~~2018 to ~~192,658~~ 331,086 Boe per day during ~~2017.~~

·2019.

Net cash provided by operating activities increased by ~~approximately $311~~$278 million to ~~$1,695~~$2,836 million ~~for 2017,~~in 2019, as compared to ~~$1,384~~ m~~illion~~$2,558 million in ~~2016,~~2018, primarily due to ~~increased~~an increase in oil and natural gas revenues and ~~decreased cash interest expense, partially offset by (i) decreased~~changes related to cash settlements on derivatives, ~~(ii) increased production expense and (iii) increased production tax expense.~~

·Cash decreased by approximately $53 million during 2017 primarily as a result of cash paid to tender and extinguish the 5.5% Notes and cash paid for the Midland Basin and Northern Delaware Basin acquisitions, partially offset by ~~proceeds from the issuance of the 2017 Notes~~an increase in operating costs on our oil and ~~proceeds from our February 2017 divestiture of ACC.~~

natural gas properties.

Commodity Prices

Our results of operations are heavily influenced by commodity prices. See “Item 1A. Risk Factors” for a description of the factors that may impact future commodity prices, including the price of oil, natural gas and natural gas liquids.

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 89 and 1719 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our commodity derivative positions at December 31, ~~2017~~2019 and additional derivative contracts entered into subsequent to December 31, ~~2017,~~2019, 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 2017 compared to 2016.~~

The following table sets forth the average NYMEX oil and natural gas prices for the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015,~~2017, as well as the high and low NYMEX prices for the same periods:

Years Ended December 31,

2017

2016

2015

Average NYMEX prices:




Oil (Bbl)

$
50.97

$
43.42

$
48.84

Natural gas (MMBtu)

$
3.02

$
2.56

$
2.63
High and Low NYMEX prices:




Oil (Bbl):

High

$
60.42

$
54.06

$
61.43

Low

$
42.53

$
26.21

$
34.73

Natural gas (MMBtu):




High

$
3.72

$
3.93

$
3.23

Low

$
2.56

$
1.64

$
1.76



	Years Ended December 31,
	2019		2018		2017
Average NYMEX prices:
Oil (Bbl)	$	57.03	$	64.81	$	50.97
Natural gas (MMBtu)	$	2.53	$	3.07	$	3.02
High and Low NYMEX prices:
Oil (Bbl):
High	$	66.30	$	76.41	$	60.42
Low	$	45.41	$	42.53	$	42.53
Natural gas (MMBtu):
High	$	3.59	$	4.84	$	3.72
Low	$	2.07	$	2.55	$	2.56

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of ~~$66.14~~$63.27 and ~~$59.19~~$49.57 per Bbl and ~~$3.63~~$2.20 and ~~$2.55~~$1.77 per MMBtu, respectively, during the period fromJanuary 1, ~~2018~~2020to February ~~16, 2018.~~14, 2020. At February ~~16, 2018,~~14, 2020, the NYMEX oil price and NYMEX natural gas price were ~~$61.68~~$52.05 per Bbl and ~~$2.56~~$1.84 per MMBtu, respectively.

Historically, and during the year ended December 31, ~~2017,~~2019, we derived a significant portion of our total natural gas revenues from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. The average Mont Belvieu price for a blended barrel of natural gas liquids was ~~$25.06~~$20.19 per Bbl, $29.94 per Bbl and ~~$18.08~~$25.06 per Bbl during the years ended December 31, 2019, 2018 and 2017, ~~and 2016,~~ respectively.

Potential cost inflation. Oilfield service and supply costs are also subject to supply and demand dynamics. As companies ~~have expanded~~expand their drilling and development activities, ~~during 2017,~~ the demand for third-party oilfield services and suppliers ~~has~~may also ~~increased.~~increase. As such, ~~if the~~when commodity ~~price environment continues~~prices begin to trend upward, we expect demand for oilfield services and supplies ~~to continue~~ to grow, and the costs of drilling, equipping and operating our wells and infrastructure could ~~begin to rise.~~

increase.

Recent Events

~~2018~~

The following are significant recent developments since our last quarterly report on Form 10-Q was filed on October 30, 2019:

2020 capital budget.In February ~~2018, we announced~~2020, our ~~2018~~board of directors approved our 2020 capital budget ~~excluding acquisitions,~~ of ~~approximately $2.0 billion with expected capital spending~~up to ~~range~~$2.9 billion. We expect to spend between ~~$1.9~~$2.6 billion and ~~$2.1 billion. Approximately 93 percent of capital will be directed to~~$2.8 billion on drilling and completion activity. ~~Our 2018 capital program is expected to continue focusing on large-scale project development. Our 2018 capital budget, based on~~

Dividends.On February 18, 2020, our ~~current expectations~~board of ~~commodity prices and costs,~~directors approved a cash dividend of $0.20 per share for the first quarter of 2020 that is expected to be ~~within~~paid on March 27, 2020 to stockholders of record as of February 28, 2020. The total cash dividend paid to our stockholders during 2019 was $100 million.

New Mexico Shelf divestiture. In November 2019, we closed on our New Mexico Shelf asset divestiture and received cash ~~flows. Our budget could change depending on numerous factors, including commodity prices, leverage metrics and industry conditions.~~

~~Tax reform.~~ ~~On December 22, 2017, the President~~proceeds of ~~the United States (“the President”) signed into law the TCJA, significantly changing corporate income tax laws. According~~$837 million, subject to ~~Accounting Standards Codification (“ASC”) section 740, “Income Taxes,” a company is required~~post-closing adjustments. Refer to record the effects of an enacted tax law or rate change in income from continuing operations in the period of enactment, which is the date the bill is signed by the President and becomes law. We note that certain aspects of these changes will impact our future after-tax earnings primarily due to the lower federal statutory tax rate. The SEC issued Staff Accounting Bulletin No. 118 “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” (“SAB 118”)to provide guidance for companies that have not completed the accounting for the income tax effects of the TCJA in the period of enactment. SAB 118 allows companies to report provisional amounts when based on reasonable estimates and to adjust these amounts during a measurement period of up to one year.

Although we have performed an initial assessment of the TCJA, we recognize that it is a comprehensive bill and the ultimate impacts may differ from our initial estimates due to changes in our interpretations as a result of additional regulatory guidance that may become available. As such, we have elected to apply SAB 118 and have recorded, based on reasonable estimates, provisional amounts of our income tax balances reported in our financial statements. See Note 115 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the New Mexico Shelf divestiture. We used the proceeds from this divestiture to repay outstanding borrowings under our ~~income tax balances.~~

AsCredit Facility and initiate the share repurchase program, as discussed below.

Share repurchase program. In September 2019, we ~~continue~~announced that our board of directors authorized the initiation of a share repurchase program for up to ~~refine~~$1.5 billion of our ~~analysis~~common stock. A portion of the ~~tax law changes and monitor new tax law interpretation, any adjustments~~proceeds from the New Mexico Shelf divestiture was used to ~~our provisional amounts identified during~~initiate the ~~measurement period will be included as an adjustment to tax expense or benefit from continuing operations in the period these amounts are determined.~~

~~Southern Delaware Basin divestitures.~~In January 2018, we closed on two asset sales transactions of certain non-core assets in Reeves and Ward Counties with combined preliminary proceeds of approximately $280 million, subject to customary post-closing adjustments.share repurchase program. As of December 31, ~~2017,~~2019, we ~~received cash deposits totaling approximately $29 million for~~had repurchased and retired 3,300,370 shares under the ~~asset sales, which was included in the total cash flows from investing activities in our consolidated statement~~program at an aggregate cost of ~~cash flows. See Note 17 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding these divestitures.~~

~~February 2018 nonmonetary transaction.~~In February 2018, we closed on a strategic trade where we received approximately 21,000 net acres, primarily located in the Midland Basin, with current production of 5 MBoepd in exchange for 34,000 net acres, primarily comprised of approximately 32,000 net acres in the northern Delaware Basin, with current production of 3 MBoepd.

$250 million.

Derivative Financial Instruments

Derivative financial instrument exposure. At December 31, ~~2017,~~2019, the fair value of our financial derivatives was a net liability of ~~$379~~$102 million. Under the terms of our financial derivative instruments, we do not have exposure to potential “margin calls” on our financial derivative instruments. The terms of our ~~credit facility~~Credit Facility do not allow us to offset amounts we may owe a lender against amounts we may be owed related to our financial instruments with such party. ~~In September 2017,~~

New commodity derivative contracts.After December 31, 2019, we ~~elected~~entered into derivative contracts to ~~enter into an “Investment Grade Period” under our credit facility, which had the effect~~hedge additional amounts of ~~releasing all collateral formerly securing the credit facility and derivative obligations. See Notes 9 and 12~~estimated future production. Refer to Note 19 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional ~~information.~~

~~New~~information regarding these commodity derivative contracts.~~After December 31, 2017, we entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts of our estimated future production:~~

First

Second

Third

Fourth

Quarter

Quarter

Quarter

Quarter

Total

Oil Price Swaps: (a)

2018:

Volume (Bbl)

915,000

1,213,000

1,013,000

674,000

3,815,000

Price per Bbl
$
63.64
$
63.48
$
63.34
$
63.11
$
63.42

2019:

Volume (Bbl)

876,000

748,000

636,000

552,000

2,812,000

Price per Bbl
$
58.14
$
58.12
$
58.10
$
58.08
$
58.11

2020:

Volume (Bbl)

1,001,000

1,001,000

1,012,000

1,012,000

4,026,000

Price per Bbl
$
54.80
$
54.80
$
54.80
$
54.80
$
54.80
Oil Basis Swaps: (b)

2018:

Volume (Bbl)

615,000

637,000

399,000

306,000

1,957,000

Price per Bbl
$
0.13
$
0.06
$
(0.07)
$
(0.10)
$
0.03

2019:

Volume (Bbl)

180,000

182,000

184,000

-

546,000

Price per Bbl
$
(0.27)
$
(0.27)
$
(0.27)
$
-
$
(0.27)

2020:

Volume (Bbl)

2,184,000

2,184,000

2,208,000

2,208,000

8,784,000

Price per Bbl
$
(0.09)
$
(0.09)
$
(0.09)
$
(0.09)
$
(0.09)
Natural Gas Price Swaps: (c)

2018:

Volume (MMBtu)

1,277,000

878,000

921,000

274,000

3,350,000

Price per MMBtu
$
3.08
$
3.08
$
3.08
$
3.08
$
3.08

(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.

Results of Operations

The following table sets forth summary ~~information concerning our~~ production and operating data for the years endedDecember 31, ~~2017, 2016~~2019, 2018and ~~2015.~~2017. The actual historical data in this table excludes results from the ~~Reliance~~RSP Acquisition for periods prior to ~~October 2016.~~July 19, 2018. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions orand divestitures, the historical information presented below should not be interpreted as being indicative of future results.



	Years Ended December 31,
	2019		2018		2017
Production and operating data:
Net production volumes:
Oil (MBbl)	76,369		61,251		43,472
Natural gas (MMcf)	266,865		208,326		161,089
Total (MBoe)	120,847		95,972		70,320

Average daily production volumes:
Oil (Bbl)	209,230		167,811		119,101
Natural gas (Mcf)	731,137		570,756		441,340
Total (Boe)	331,086		262,937		192,658

Average prices per unit: (a)
Oil, without derivatives (Bbl)	$	54.03	$	56.22	$	48.13
Oil, with derivatives (Bbl) (b)	$	52.35	$	52.73	$	49.93
Natural gas, without derivatives (Mcf)	$	1.74	$	3.40	$	3.07
Natural gas, with derivatives (Mcf) (b)	$	1.86	$	3.37	$	3.06
Total, without derivatives (Boe)	$	38.00	$	43.25	$	36.78
Total, with derivatives (Boe) (b)	$	37.19	$	40.98	$	37.88

Operating costs and expenses per Boe: (a)
Oil and natural gas production	$	5.93	$	6.14	$	5.80
Production and ad valorem taxes	$	2.89	$	3.19	$	2.82
Gathering, processing and transportation	$	0.96	$	0.58	$	—
Depreciation, depletion and amortization	$	16.25	$	15.41	$	16.29
General and administrative	$	2.69	$	3.25	$	3.46



(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:

		Years Ended December 31,
	(in millions)	2019			2018			2017
	Net cash receipts from (payments on) derivatives:
	Oil derivatives	$	(129	)	$	(213	)	$	79
	Natural gas derivatives	31			(5		)	—
	Total	$	(98	)	$	(218	)	$	79

	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.

The following table presents selected production data for the fields ~~which~~that represent greater than 15 percent of our total proved reserves at December 31, ~~2017, 2016~~2019, 2018 and ~~2015:~~

2017:

Year Ended December 31,

2017

2016

2015

Production:

South Basin Wolfcamp Bone Spring:

Oil (MMBbl)

12

11

10

Natural gas (Bcf)

75

56

37

Total (MMBoe)

25

20

16

Midland Basin Spraberry-Wolfcamp:

Oil (MMBbl)

8

6

(a)

Natural gas (Bcf)

26

20

(a)

Total (MMBoe)

12

9

(a)

Yeso:

Oil (MMBbl)

7

7

7

Natural gas (Bcf)

28

27

27

Total (MMBoe)

12

12

12

(a) Represented less than 15% of the Company's total proved reserves for the year indicated.



	Years Ended December 31,
	2019	2018	2017
Production:
Delaware Basin:
Oil (MMBbl)	44	34	25
Natural gas (Bcf)	170	130	103
Total (MMBoe)	72	56	42
Midland Basin:
Oil (MMBbl)	29	21	11
Natural gas (Bcf)	76	52	30
Total (MMBoe)	42	30	16
Yeso:
Oil (MMBbl)	(a)	(a)	7
Natural gas (Bcf)	(a)	(a)	28
Total (MMBoe)	(a)	(a)	12


(a)	Represents less than 15% of our total proved reserves for the year indicated.

~~Year Ended~~

The following tables and related discussion set forth key operating and financial data as of and for the years ended December 31, 2019 and 2018. For similar operating and financial data and discussion of our 2018 results compared to our 2017 ~~Compared~~results, refer to ~~Year Ended~~“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Part II of our annual report on Form 10-K for the year ended December 31, ~~2016~~

2018, which was filed with the SEC on February 20, 2019.

Oil and natural gas revenues. Revenue from oil and natural gas operations was$~~2,586~~4,592 million for the year endedDecember 31, ~~2017~~,2019, an increase of$~~951~~441 million ~~(58~~ ~~percent~~)(11 percent) from ~~$1,635~~$4,151 million for ~~2016. This~~2018. The increase was primarily due to the increase in ~~realized~~ oil and natural gas production, ~~as well as~~in part due to the ~~increase~~RSP Acquisition, partially offset by the decrease in realized oil and natural gas prices (excluding the effects of derivative activities).

Specific factors affecting oil and natural gas revenues for the years ended December 31, 2019 and 2018 include the following:



	Years Ended December 31,
	2019			2018
Net production volumes:
Oil (MBbl)	76,369			61,251
Natural gas (MMcf)	266,865			208,326

Average prices per unit:
Average NYMEX oil price (Bbl)	$	57.03		$	64.81
Realized oil price (Bbl)	$	54.03		$	56.22
Differential to NYMEX	$	(3.00	)	$	(8.59	)

Average NYMEX natural gas price (MMBtu)	$	2.53		$	3.07
Realized natural gas price (Mcf)	$	1.74		$	3.40
Average realized natural gas price as a percentage of NYMEX	69		%	111		%

total oil production ~~was 43,472~~ increased 15,118 MBbl (25 percent) for the year ended December 31, ~~2017, an~~ ~~increase~~ ~~of 9,632~~ ~~MBbl~~ ~~(28~~ ~~percent) from 33,840~~ ~~MBbl~~ ~~for~~ ~~2016~~;

·2019 as compared to 2018;

average realized oil price (excluding the effects of derivative activities) ~~was~~ ~~$48.13~~ ~~per Bbl during~~decreased 4 percent for the year ended December 31, ~~2017, an increase of 21~~ ~~percent~~ ~~from~~ ~~$39.90~~ ~~per Bbl during~~ ~~2016.~~ ~~For the year ended~~ ~~December 31, 2017, our crude oil price differential relative to NYMEX was $(2.84) per Bbl, or a realization of approximately 94 percent,~~2019 as compared to ~~a crude~~2018. The decrease in average realized oil price ~~differential relative~~was primarily due to a decrease in the average NYMEX price, partially offset by the narrowing of ~~$(3.52) 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 ~~year~~years ended December 31, ~~2017~~2019 and ~~2016,~~2018, the average market ~~basis differential between WTI-Midland and WTI-Cushing was a~~Mid-Cush differentials were price ~~reduction~~reductions of ~~$0.30~~$1.49 per Bbl and ~~$0.15~~$6.51 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~~respectively;

total natural gas production increased 58,539 MMcf (28 percent) for the year ended December 31, ~~2017~~2019 as compared to ~~2016 primarily due to more production transported through pipelines~~2018; and ~~successful renegotiation of fixed deductions for trucked volumes;~~

·~~total natural gas production was 161,089~~ ~~MMcf~~ ~~for the year ended~~ ~~December 31, 2017, an~~ ~~increase~~ ~~of 33,608~~ ~~MMcf~~ ~~(26~~ ~~percent) from 127,481~~ ~~MMcf~~ ~~for~~ ~~2016; and~~

average realized natural gas price (excluding the effects of derivative activities) ~~was~~ ~~$3.07~~ ~~per Mcf during the year ended~~ ~~December 31, 2017, an increase of 38~~ decreased 49 percent ~~from~~ ~~$2.23~~ ~~per Mcf during~~ ~~2016. For the years ended~~ ~~December 31, 2017 and 2016, we realized approximately 102 percent and 87 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 year ended December 31, ~~2017~~2019 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 year ended December 31, 2017, we derived~~2018. We derive a significant portion of our total natural gas revenues from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. The average Mont Belvieu price for a blended barrel of natural gas liquids ~~was $25.06 per Bbl and $18.08~~decreased from $29.94 per Bbl during the ~~years~~year ended December 31, ~~2017~~2018 to $20.19 per Bbl during the year ended December 31, 2019. In addition, during the latter part of 2018 and ~~2016, respectively.~~

into 2019, amid concerns of rising natural gas production relative to the ability to transport natural gas out of the Permian Basin, the price differential for natural gas residue increased significantly. These widening natural gas residue differentials negatively impacted our realized natural gas prices during the year ended December 31, 2019. The combination of these factors resulted in a realized natural gas price of 69 percent of the average NYMEX natural gas price for the year ended December 31, 2019. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues and the Permian Basin local markets for residue gas settling more in parity with NYMEX price, our realized natural gas price (excluding the effects of derivatives) for the year ended December 31, 2018 reflected a price greater than the related NYMEX natural gas price.

Oil and natural gas production expenses. The following table provides the components of our oil and natural gas production expenses for the years endedDecember 31, ~~2017~~2019 and ~~2016:~~

2018:

��




Years Ended December 31,

2017

2016

Per

Per
(in millions, except per unit amounts)


Amount

Boe

Amount

Boe

Lease operating expenses

$
387

$
5.50

$
301

$
5.46
Workover costs

21

0.30

19

0.35

Total oil and natural gas production expenses

$
408

$
5.80

$
320

$
5.81



(in millions, except per unit amounts)	Years Ended December 31,
	2019				2018
	Amount		Per Boe		Amount		Per Boe
Lease operating expenses	$	681	$	5.64	$	553	$	5.76
Workover costs	35		0.29		37		0.38
Total oil and natural gas production expenses	$	716	$	5.93	$	590	$	6.14

Lease operating expenses were ~~$387~~$681 million ($~~5.50~~5.64 per Boe) for the year ended December 31, ~~2017, which was~~2019, an increase of ~~$86~~$128 million ~~(29~~(23 percent) from ~~$301~~$553 million ($~~5.46~~5.76 per Boe) for 2018. The increase in lease operating expenses during 2019 as compared to the prior year was primarily the result of an increase in well count due to our acquisitions during 2018, and additional wells successfully drilled and completed during 2018 and 2019, partially offset by the New Mexico Shelf divestiture. The decrease in lease operating expenses per Boe was primarily due to higher production from our drilling program during 2019 and the New Mexico Shelf divestiture.

Workover costs were $35 million ($0.29 per Boe) for the year ended December 31, ~~2016~~.2019, a decrease of $2 million from $37 million ($0.38 per Boe) for2018. The ~~increase~~decrease in ~~lease operating expenses~~workover costs per Boe during 2019 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 during 2017, particularly our Reliance Acquisition and our Midland Basin acquisition, whose associated properties incur higher lease operating expense per Boe than our legacy assets and (iii) increased cost of services.

decreased workover activity.

Production and ad valorem taxes. The following table provides the components of our production and ad valorem tax expenses for the years endedDecember 31, ~~2017~~2019 and ~~2016:~~

2018:

Years Ended December 31,

2017

2016

Per

Per
(in millions, except per unit amounts)


Amount

Boe

Amount

Boe

Production taxes

$
181

$
2.58

$
117

$
2.13
Ad valorem taxes


18

0.24

14

0.25

Total production and ad valorem taxes

$
199

$
2.82

$
131

$
2.38



(in millions, except per unit amounts)	Years Ended December 31,
	2019				2018
	Amount		Per Boe		Amount		Per Boe
Production taxes	$	282	$	2.33	$	272	$	2.84
Ad valorem taxes	67		0.56		33		0.35
Total production and ad valorem taxes	$	349	$	2.89	$	305	$	3.19

Production taxes per unit of production were ~~$2.58~~$2.33 per Boe during the year ended December 31, ~~2017, an increase~~2019, a decrease of 2118 percent from ~~$2.13~~$2.84 per Boe during ~~2016~~.2018. Over the same period, our revenue per Boe (excluding the effects of derivatives) ~~increased 24~~decreased 12 percent. The ~~increase~~decrease in production taxes per unit of production was ~~directly related~~due to ~~the increase in oil and natural gas sales, partially offset by~~lower realized revenue per Boe along with a ~~$5 million tax credit received during 2017 related to certain wells~~higher percentage of our total production originating in Texas, ~~qualifying for reduced severance~~which has a lower tax ~~rates, as compared to $4 million in tax credit received during 2016.~~ 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 $34 million during the year ended December 31, 2019 as compared to the year ended December 31, 2018, primarily due to additional wells drilled and completed, new wells acquired and an increase in tax rates in certain counties. The increase in ad valorem taxes per Boe during the year ended December 31, 2019 as compared to the year ended December 31, 2018 was primarily due to an increase in tax rates.

Gathering, processing and transportation costs.The following table shows the gathering, processing and transportation costsfor the years endedDecember 31, 2019 and 2018:



	Years Ended December 31,
(in millions, except per unit amounts)	2019				2018
(in millions, except per unit amounts)	Amount		Per Boe		Amount		Per Boe
Gathering, processing and transportation costs	$	115	$	0.96	$	55	$	0.58

Gathering, processing and transportation costs were $115 million ($0.96 per Boe) for the year endedDecember 31, 2019, an increase of 109 percent from $55 million for 2018. The increase in gathering, processing and transportation costs for 2019 was primarily due to a certain crude oil gathering and transportation contract that, among other things, was modified to allow repurchase rights. As such, costs related to this contract that were previously recorded as a deduction to revenue during 2018 are now recorded in gathering, processing and transportation costs. In addition, contributing to the increase in gathering, processing and transportation costs was the RSP Acquisition and the increase in production. The increase in gathering, processing and transportation costs per Boe was primarily related to the aforementioned crude oil gathering and transportation contract and fixed costs associated with

certain contracts. Additionally, we entered into a marketing contract that requires us to deliver 50,000 barrels of oil per day that began in October 2019. As a result of this contract, we expect our realized oil prices, as well as our gathering, processing and transportation costs, to increase for the related oil production in future periods.

Exploration and abandonments expense.The following table provides the components of our exploration and abandonments expense for theyearsendedDecember 31, ~~2017~~2019 and ~~2016:~~

2018:

Years Ended December 31,
(in millions)

2017

2016

Geological and geophysical

$
13

$
8
Exploratory dry hole costs


-

7
Leasehold abandonments


27

50
Other

19

12

Total exploration and abandonments

$
59

$
77



(in millions)	Years Ended December 31,
(in millions)	2019		2018
Geological and geophysical	$	17	$	12
Leasehold abandonments	147		35
Other	37		18
Total exploration and abandonments	$	201	$	65

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 year ended~~ ~~December 31, 2016~~ ~~were primarily related to an uneconomic well in our Northern Delaware Basin core area that was attempting to establish commercial production through testing~~

We recorded $147 million and $35 million of ~~multiple zones. We did not recognize any exploratory dry hole costs during the year ended~~ ~~December 31, 2017~~.

~~For~~leasehold abandonments for the years ended December 31, ~~2017~~2019 and ~~2016, we recorded approximately $29 million and $60 million,~~2018, respectively, ~~of leasehold abandonments. For the year ended December 31, 2017, our abandonments were~~ primarily related to ~~(i)~~certain expiring 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~~had no ~~future~~ plans to ~~drill. For~~extend the ~~year ended December 31, 2016, our abandonments were primarily related to (i) drilling locations in our Northern Delaware Basin~~lease and ~~New Mexico Shelf core areas that, 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~~had no ~~future development~~long-term plans ~~and (iii) expiring acreage primarily located in our Northern Delaware Basin and Southern Delaware Basin areas.~~

to drill.

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

The increase in other expense during 2019 was primarily due to the abandonments of certain exploratory wells, in part due to mechanical issues encountered during the completion of certain wells that made them unable to produce hydrocarbons in economic quantities.

Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the years endedDecember 31, ~~2017~~2019 and ~~2016:~~

2018:

Years Ended December 31,

2017

2016

Per

Per
(in millions, except per unit amounts)


Amount

Boe

Amount

Boe

Depletion of proved oil and natural gas properties

$
1,122

$
15.95

$
1,145

$
20.79
Depreciation of other property and equipment


21

0.29

21

0.37
Amortization of intangible assets


3

0.05

1

0.03

Total depletion, depreciation and amortization

$
1,146

$
16.29

$
1,167

$
21.19

Oil price used to estimate proved oil reserves at period end

$
47.79

$
39.25

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

$
2.98

$
2.48



(in millions, except per unit amounts)	Years Ended December 31,
	2019				2018
	Amount		Per Boe		Amount		Per Boe
Depletion of proved oil and natural gas properties	$	1,932	$	15.98	$	1,453	$	15.14
Depreciation of other property and equipment	30		0.25		22		0.23
Amortization of intangible assets	2		0.02		3		0.04
Total depletion, depreciation and amortization	$	1,964	$	16.25	$	1,478	$	15.41

Oil price used to estimate proved oil reserves at period end	$	52.19			$	62.04
Natural gas price used to estimate proved natural gas reserves at period end	$	2.58			$	3.10

Depletion of proved oil and natural gas properties was ~~$1,122~~$1,932 million ($~~15.95~~15.98 per Boe) for the year ended December 31, ~~2017, a decrease~~2019, an increase of ~~$23~~$479 million (2(33 percent) from ~~$1,145~~$1,453 million ($~~20.79~~15.14 per Boe) for ~~2016.~~2018. The ~~decrease~~increase in depletion expense was ~~primarily~~ due to ~~a lower~~an increase in production and the depletion rate per ~~Boe partially offset by an~~Boe. The increase ~~in production. The decrease~~ in depletion expense per Boe was primarily due to ~~(i) lower drilling~~the RSP Acquisition and ~~completion costs per Boe of proved developed reserves added, (ii) an overall increase in proved reserves primarily caused by~~certain downward adjustments to our successful exploratory drilling program, the Reliance Acquisition as well as other acquisitions, and higher commodity prices, 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 the date of their initial recognition 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 reserves, partially offset by lower depletion of the Yeso field due to the impairment charge recognized during 2019, as discussed below, and the New Mexico Shelf divestiture.

Impairments of long-lived assets. During the year ended December 31, 2019, we recognized impairments of long-lived assets of $890 million. During the second quarter of 2019, we recognized an impairment charge of $868 million that was primarily attributable to certain downward adjustments to our economically recoverable proved oil and natural gas reserves associated with properties ~~and their integrated assets, whenever events or circumstances indicate that~~in our Yeso field due to the decline in commodity prices. During the third quarter of 2019, we recognized an additional impairment charge of $20 million primarily to reduce the carrying value of ~~those~~the remaining 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 December 31, 2017, our estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a 2018 price of $59.55 per barrel of oil decreasing to a 2024 price of $51.82 per barrel of oil marginally recovering to a 2025 price of $51.83 per barrel of oil. Similarly, natural gas prices ranged from a 2018 price of $2.84 per Mcf of natural gas decreasing to a 2019 price of $2.81 per Mcf then rising to a 2025 price of $2.99 per Mcf of natural gas. Both oil and natural gas commodity prices for this purpose were held flat after 2025.

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.

~~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~~to their fair value. Our Yeso field was primarily composed of the New Mexico Shelf ~~core area exceeded the expected undiscounted future net cash flows resulting~~assets that we sold 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.November 2019. We did not recognize an impairment ~~charge~~ during 2018. See Note 8 of the ~~year ended December 31, 2017.~~

Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information on the fair value assumptions used for long-lived assets.

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

~~We estimate that if~~assets.

Impairments of goodwill. During the ~~future oil and natural gas prices used in this analysis, and noted above, would have been approximately 10 percent lower at~~year ended December 31, 2017 with no other changes in capital costs, operating costs, price differentials, or reserve performance curves, no impairment would be indicated. 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,2019, 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~~recognized goodwill impairments 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~~$282 million. The impairments were due to ~~predict with certainty whether or not~~ a decline in ~~commodity prices alone will or will not cause us to recognize an impairment charge~~our market capitalization along with declines in ~~a particular field or~~observed control premiums during the ~~magnitude~~second half 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,~~2019 and the ~~amount~~New Mexico Shelf divestiture. See Note 2 of ~~proved undeveloped locations that can be recorded, each~~the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information on the impairment of ~~which will affect management’s estimates of future cash flows.~~

our goodwill.

General and administrative expenses.The following table provides components of our general and administrative expenses for the years endedDecember 31, ~~2017~~2019 and ~~2016:~~

2018:

Years Ended December 31,

2017

2016

Per

Per
(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

General and administrative expenses

$
200

$
2.85

$
184

$
3.33
Less: Operating fee reimbursements


(16)

(0.24)

(17)

(0.31)
Non-cash stock-based compensation


60

0.85

59

1.07

Total general and administrative expenses

$
244

$
3.46

$
226

$
4.09

~~General~~



(in millions, except per unit amounts)	Years Ended December 31,
	2019						2018
	Amount			Per Boe			Amount			Per Boe
General and administrative expenses	$	259		$	2.13		$	248		$	2.58
Less: Operating fee reimbursements	(18		)	(0.15		)	(19		)	(0.19		)
Non-cash stock-based compensation	85			0.71			82			0.86
Total general and administrative expenses	$	326		$	2.69		$	311		$	3.25

Total general and administrative expenses were ~~approximately $244~~$326 million ($~~3.46~~2.69 per Boe) for the year endedDecember 31, ~~2017~~,2019, an increase of ~~$18~~$15 million (8(5 percent) from ~~$226~~$311 million ($~~4.09~~3.25 per Boe) for~~2016~~.2018. The increase in ~~cash~~total general and administrative expenses was primarily ~~a result of increased~~due to an increase in the average employee headcount, in part due to the RSP Acquisition, partially offset by lower variable compensation ~~expense.~~accruals during 2019. The decrease in total general and administrative expenses per Boe was primarily ~~due to~~the result of increased production, partially offset by the increase in ~~cash~~total general and administrative ~~costs noted above.~~

expenses.

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 ofto general and administrative expenses in the consolidated statements of operations. We earned reimbursements of approximately ~~$16~~$18 million and ~~$17~~$19 million during the years ended December 31, ~~2017~~2019 and ~~2016,~~2018, respectively.

Gain (loss) on derivatives.The following table sets forth the gain (loss) on derivatives for the years endedDecember 31, ~~2017~~2019 and ~~2016:~~

2018:

Years Ended

December 31,
(in millions)

2017

2016

Gain (loss) on derivatives:

Oil derivatives

$
(172)

$
(337)

Natural gas derivatives

46

(32)

Total

$
(126)

$
(369)

       The following table represents our net cash receipts from derivatives for the years ended December 31, 2017 and 2016:

Years Ended

December 31,
(in millions)

2017

2016

Net cash receipts from derivatives:

Oil derivatives

$
79

$
609

Natural gas derivatives


-


16

Total

$
79

$
625



(in millions)	Years Ended December 31,
(in millions)	2019			2018
Gain (loss) on derivatives:
Oil derivatives	$	(1,003	)	$	848
Natural gas derivatives	108			(16		)
Total	$	(895	)	$	832

The following table represents our net cash receipts from (payments on) derivatives for the years ended December 31, 2019 and 2018:



(in millions)	Years Ended December 31,
(in millions)	2019			2018
Net cash receipts from (payments on) derivatives:
Oil derivatives	$	(129	)	$	(213	)
Natural gas derivatives	31			(5		)
Total	$	(98	)	$	(218	)

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 future commodity price outlook increases between measurement periods, we will have mark-to-market losses. See Note 78 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding significant judgments made in classifying financial instruments in the fair value hierarchy.

Gain on disposition of assets, net.During the ~~years~~year ended December 31, ~~2017 and 2016,~~2019, we ~~recognized~~recorded a net gain on disposition of assets of ~~approximately $678~~$170 million, primarily due to a gain of $297 million related to our contribution of certain water infrastructure assets in exchange for a cash distribution and ~~$118 million, respectively. In February 2017, we closed on the~~

~~divestiture of our~~an equity ownership interest in ~~ACC. After adjustments for debt~~an entity, partially offset by losses related to certain nonmonetary transactions and ~~working capital,~~the New Mexico Shelf divestiture.

During the year ended December 31, 2018, we ~~received cash proceeds from the sale of approximately $801 million. After direct transaction costs, we recorded~~recognized a ~~pre-tax~~net gain on disposition of assets of ~~approximately $655 million. Our net investment~~$800 million, which was primarily due to (i) a gain of $575 million related to our February 2018 acquisition and divestiture primarily in ~~ACC at~~ the ~~time~~Midland Basin, (ii) a gain of ~~closing was approximately $129 million.~~ ~~In February 2016, we sold~~$134 million related to our Delaware Basin divestiture in January 2018 and (iii) a gain of $79 million related to the contribution of certain infrastructure assets in ~~our Northern~~the southern portion of the Delaware ~~Basin core area~~Basin. In addition, during 2018, we completed multiple nonmonetary transactions that included the exchange of both proved and unproved oil and natural gas properties that resulted in pre-tax gains of $15 million.

Refer to Notes 2 and 5 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for ~~proceeds~~further discussion of ~~approximately $292 million~~certain of the 2019 and ~~recognized a pre-tax gain of approximately $110 million.~~

2018 transactions mentioned above.

Interest expense.The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the years endedDecember 31, ~~2017~~2019 and ~~2016:~~

2018:

Years Ended December 31,
(in millions)

2017

2016

Interest expense, as reported

$
146

$
204
Capitalized interest

3

-

Interest expense, excluding impact of capitalized interest

$
149

$
204



Weighted average interest rate – credit facility

3.5%

-
Weighted average interest rate – senior notes

5.0%

5.9%

Total weighted average interest rate


5.0%

5.9%

Weighted average credit facility balance

$
100

$
-
Weighted average senior notes balance

2,658

3,182

Total weighted average debt balance

$
2,758

$
3,182

~~Our weighted average debt balance decreased for~~



(in millions)	Years Ended December 31,
(in millions)	2019			2018
Interest expense, as reported	$	185		$	149
Capitalized interest	19			8
Interest expense, excluding impact of capitalized interest	$	204		$	157

Weighted average interest rate – Credit Facility	4.2		%	4.5		%
Weighted average interest rate – senior notes	4.4		%	4.3		%
Total weighted average interest rate	4.4		%	4.3		%

Weighted average Credit Facility balance	$	439		$	172
Weighted average senior notes balance	4,000			3,195
Total weighted average debt balance	$	4,439		$	3,367

The increase in interest expense during the year ended December 31, ~~2017~~2019 as compared to ~~2016~~2018 was primarily due to ~~(i)~~ the satisfaction and discharge of the 6.5% Notes in December 2016, (ii) the redemption of the 7.0% Notes in September 2016 and (iii) the satisfaction and discharge of the 5.5% Notes in September 2017, partially offset by (i) the issuance of the 4.375% Notes in December 2016, (ii) the issuance of the 2017 Notes in September 2017 and (iii) an increase ~~in borrowings under our credit facility. The decrease in interest expense was due to the overall decrease~~ in the weighted average debt balance, ~~and an~~partially offset by the increase in capitalized ~~interest.~~

~~Loss~~interest and lower weighted average interest rate on ~~extinguishment of debt.~~~~We recorded a loss on extinguishment of debt of $66 million for the~~ ~~year ended~~ ~~December 31, 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 longerour Credit Facility. The increase in the ~~credit facility syndicate as a result of the April 2017 credit facility amendment.~~

We recorded a loss on extinguishment of debt of $56 million for the year ended December 31, 2016. This amount includes: (i) approximately $20 million associated with the make-whole premium paid for the early extinguishment of the 6.5% Notes in December 2016, approximately $7 million of related unamortized deferred loan costs and approximately $1 million of additional interest on the 6.5% Notes through January 16, 2017, which was paid in December 2016; and (ii) $21 million associated with the make-whole premium paid for the early redemption of the 7.0% Notes in September 2016 and approximately $7 million of related unamortized deferred loan costs.

~~Income tax provisions.~~ ~~For the year ended December 31,~~ ~~2017~~, we recorded an income tax benefit of $75 million, which includes discrete provisional income tax benefits of approximately $398 million related to the enactment of the TCJA and $6 million related to stock-based awards recorded in the income tax provision pursuant to ASU No. 2016-09 adopted on January 1, 2017. For the year ended ~~December 31,~~ ~~2016, we recorded an income tax benefit of $876 million primarily due to having a loss before income taxes.~~

~~The change in our income tax provision in 2017 as compared to 2016~~weighted average senior notes balance was primarily due to the ~~favorable impacts of the tax law changes enacted through the TCJA~~senior notes issued in December 2017 as the income tax benefit related to the federal statutory rate change more than offset our income tax expense of $308 million on income before income taxes during 2017. The effective income tax rates for the years ended December 31, 2017 and 2016 were (9) percent and 38 percent, respectively. The 2017 rate was negative due to recognizing an overall income tax benefit while having pre-tax income.

~~As we continue to implement and address the ongoing impacts of the TCJA, we may determine it necessary in the future to adjust our income tax calculations~~ ~~due to changes in our initial interpretations or assumptions. As we have elected to apply~~

~~SAB 118, adjustments to provisional amounts included in the total income tax benefit are allowable during the one-year measurement period. We will continue to monitor new tax law interpretations.~~

We evaluate changes to our industry, production, market conditions and changes in our forecasted drilling plan by tax jurisdiction. Our material state tax jurisdictions include Texas and New Mexico. In February 2017, we sold our ownership interest in ACC, which consisted of property in both Texas and New Mexico, and in April 2017, we completed an acquisition of assets in the Northern Delaware Basin. We have considered these and other factors and did not identify a shift in our projected future apportionment between New Mexico and Texas for the year ended December 31, 2017. In October 2016, we purchased Texas-based assets in the Reliance Acquisition for approximately $1.7 billion, which caused a shift in our projected future apportionment from New Mexico to Texas, which has a lower statutory state tax rate than New Mexico. As such, we recognized an overall state deferred tax benefit of approximately $21 million for the year ended December 31, 2016.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~

~~Oil and natural gas revenues.~~ ~~Revenue from oil and natural gas operations was$1,635 million for the year ended~~ ~~December 31, 2016, a decrease of $169 million (9 percent) from $1,804 million for~~ ~~2015~~. This decrease was primarily due to the decrease in realized oil and natural gas prices partially offset by an increase in natural gas production. Specific factors affecting oil and natural gas revenues include the following:

·~~total oil production was 33,840~~ ~~MBbl~~ ~~for the year ended~~ ~~December 31, 2016, a decrease of 617~~ ~~MBbl~~ (2 ~~percent) from 34,457~~ ~~MBbl~~ ~~for~~ ~~2015~~;

·~~average realized oil price (excluding the effects of derivative activities) was~~ ~~$39.90~~ ~~per Bbl during the year ended~~ ~~December 31, 2016, a decrease of 11~~ ~~percent~~ ~~from~~ ~~$44.69~~ ~~per Bbl during~~ ~~2015.~~ ~~For the year ended~~ ~~December 31, 2016~~, our crude oil price differential relative to NYMEX was $(3.52) per Bbl, or a realization of approximately 92 percent, as compared to a crude oil price differential relative to NYMEX of $(4.15) per Bbl, or a realization of approximately 92 percent, for 2015. We incur fixed deductions from the posted Midland oil price based on the location of our oil within the Permian Basin. Additionally, 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 years ended ~~December 31, 2016 and 2015, the average market basis differential between WTI-Midland and WTI-Cushing was a price reduction of $0.15 per Bbl and $0.41 per Bbl, respectively;~~

·~~total natural gas production was 127,481~~ ~~MMcf~~ ~~for the year ended~~ ~~December 31, 2016, an increase of 20,494~~ ~~MMcf~~ ~~(19~~ ~~percent) from 106,987~~ ~~MMcf~~ ~~for~~ ~~2015; and~~

·~~average realized natural gas price (excluding the effects of derivative activities) was~~ ~~$2.23~~ ~~per Mcf during the year ended~~ ~~December 31, 2016, a decrease of 9~~ ~~percent~~ ~~from~~ ~~$2.46~~ ~~per Mcf during~~ ~~2015. For the years ended~~ ~~December 31, 2016 and 2015~~, we realized approximately 87 percent and 94 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Factors contributing to the decrease in our realized gas price (excluding the effects of derivatives) as a percentage of NYMEX during the year ended ~~December 31, 2016~~ ~~as compared to~~ ~~2015~~ were (i) a decrease in the posted regional natural gas prices on which we are paid while the NYMEX natural gas price decreased at a lesser rate and (ii) increased deductions and fees from the regional natural gas price, comparatively. Over the past three years, approximately half of our total natural gas revenues have been derived from the value of the natural gas liquids contained in our natural gas,connection 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 $18.08 per Bbl and $17.80 per Bbl during the years ended December 31, 2016 and 2015, respectively.

RSP Acquisition.

~~Oil and natural gas production expenses.~~ ~~The following table provides the components of our oil and natural gas production expenses for the years ended~~ ~~December 31, 2016~~ ~~and 2015:~~

Years Ended December 31,

2016

2015

Per

Per
(in millions, except per unit amounts)


Amount

Boe

Amount

Boe

Lease operating expenses

$
301

$
5.46

$
362

$
6.93
Workover costs


19

0.35

28

0.53

Total oil and natural gas production expenses

$
320

$
5.81

$
390

$
7.46

Among the cost components of production expenses, we have some control over lease operating expenses and workover costs on properties we operate, but production and ad valorem taxes are related to commodity prices.

Lease operating expenses were $301 million ($5.46 per Boe) for the year ended December 31, 2016, which was a decrease of $61 million (17 percent) from $362 million ($6.93 per Boe) for the year ended December 31, 2015. The decrease in lease operating expenses was primarily due to (i) implementation of operational cost efficiencies and (ii) an overall decrease in the cost of goods and services. The decrease in lease operating expenses per Boe was primarily due to the reduction in lease operating expenses noted above coupled with a slight increase in production.

~~Workover expenses were approximately $19 million and $28 million for the years ended December 31, 2016 and 2015, respectively.~~ ~~The decrease was primarily related to less overall activity during 2016 as compared to 2015.~~

~~Production and ad valorem taxes.~~ ~~The following table provides the components of our production and ad valorem tax expenses for the years ended~~ ~~December 31, 2016~~ ~~and 2015:~~

Years Ended December 31,

2016

2015

Per

Per
(in millions, except per unit amounts)


Amount

Boe

Amount

Boe

Production taxes

$
117

$
2.13

$
128

$
2.46
Ad valorem taxes


14

0.25

23

0.44

Total production and ad valorem taxes

$
131

$
2.38

$
151

$
2.90

~~Production taxes per unit of production were $2.13 per Boe during the year ended December 31, 2016, a decrease of 13 percent from $2.46 per Boe during 2015.~~ ~~The decrease was directly related to the decrease in oil and natural gas prices. Over the same period, our average realized prices per Boe (excluding the effects of derivatives) decreased 14 percent.~~

~~Exploration and abandonments expense.~~ ~~The following table provides the components of our exploration and abandonments expense for the~~ ~~years~~ ~~ended~~ ~~December 31, 2016~~ ~~and 2015:~~

Years Ended December 31,
(in millions)

2016

2015

Geological and geophysical

$
8

$
10
Exploratory dry hole costs


7

9
Leasehold abandonments


50

25
Other

12

15

Total exploration and abandonments

$
77

$
59

~~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 year ended December 31, 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. Our exploratory dry hole costs during the year ended ~~December 31, 2015~~ were primarily related to (i) an uneconomic well in our Southern Delaware Basin core area that was attempting to establish production in an unconventional zone for the area and (ii) expensing an unsuccessful well, which we did not operate, that was located in our New Mexico Shelf core area.

Other income, net.During the year ended December 31, ~~2016,~~2019, we ~~recognized leasehold abandonment expense~~recorded other income of ~~approximately $50~~$313 million, primarily related to ~~(i) drilling locations~~$289 million of cash proceeds from the sale of our ownership interest in ~~our Northern~~Oryx I, a crude oil gathering and transportation system in the 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 primarily located in our Northern Delaware Basin and Southern Delaware Basin core areas.

During the year ended December 31, 2015, we recognized leasehold abandonment expense of approximately $25 million primarily related to expired and abandoned acreage in our Northern Delaware Basin core area where we currently have no intent to drill.

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

~~Depreciation, depletion and amortization expense.~~ ~~The following table provides components of our depreciation, depletion and amortization expense for the years ended~~ ~~December 31, 2016~~ ~~and 2015:~~

Years Ended December 31,

2016

2015

Per

Per
(in millions, except per unit amounts)


Amount

Boe

Amount

Boe

Depletion of proved oil and natural gas properties

$
1,145

$
20.79

$
1,203

$
23.02
Depreciation of other property and equipment


21

0.37

19

0.35
Amortization of intangible assets


1

0.03

1

0.03

Total depletion, depreciation and amortization

$
1,167

$
21.19

$
1,223

$
23.40

Oil price used to estimate proved oil reserves at period end

$
39.25

$
46.79

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

$
2.48

$
2.59

Depletion of proved oil and natural gas properties was $1,145 million ($20.79 per Boe) for the year ended December 31, 2016, a decrease of $58 million (5 percent) from $1,203 million ($23.02 per Boe) for 2015. The decrease in depletion expense was primarily due to a lower depletion rate per Boe partially offset by an increase in production. The decrease in depletion expense per Boe was primarily due to (i) a non-cash impairment charge of approximately $1.5 billion recorded in the first quarter of 2016 and (ii) an overall increase in proved reserves primarily caused by our successful exploratory drilling program, the Reliance Acquisition and reductions in future estimated lease operating expenses, partially offset by decreased proved

reserves caused by (i) reclassification of proved undeveloped reserves to unproved reserves because they are no longer expected to be developed within five years of the date of their initial recognition and (ii) lower commodity prices.

~~The increase in depreciation expense was primarily associated with additional other property and equipment related to buildings and other items.~~

~~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 calculate the expected 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 December 31, 2016, 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 $56.19 per barrel of oil to a 2024 price of $57.41 per barrel of oil. Similarly, natural gas prices ranged from a 2017 price of $3.61 per Mcf of natural gas decreasing to a 2020 price of $2.88 per Mcf of natural gas partially recovering to a 2024 price of $3.38 per Mcf of natural gas. Commodity prices for this purpose were held flat after 2024.

We calculate the estimated 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.

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 2022 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 2022.

We recognized a non-cash charge against earnings of approximately $61 million for the year ended December 31, 2015 as a result of the carrying amount of certain of our long-lived assets and their integrated assets being less than their expected undiscounted future net cash flows, which was primarily attributable to properties in our eastern Midland Basin area.

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. If the oil and natural gas prices used in this analysis would have been approximately 10 percent lower as of December 31, 2016 with no other changes in capital costs, operating costs, price differentials, or reserve volumes, no impairment would be indicated.

~~General and administrative expenses.~~~~The following table provides components of our general and administrative expenses for the years ended~~ ~~December 31, 2016~~ ~~and 2015:~~

Years Ended December 31,

2016

2015

Per

Per
(in millions, except per unit amounts)

Amount

Boe

Amount

Boe

General and administrative expenses

$
184

$
3.33

$
187

$
3.58
Less: Operating fee reimbursements


(17)

(0.31)

(19)

(0.37)
Non-cash stock-based compensation


59

1.07

63

1.21

Total general and administrative expenses

$
226

$
4.09

$
231

$
4.42

~~General and administrative expenses were approximately $226 million ($4.09 per Boe) for the year ended~~ ~~December 31, 2016, a decrease of $5 million (2 percent) from $231 million ($4.42 per Boe) for~~ ~~2015~~(“Oryx I”). The decrease in non-cash stock-based compensation was primarily due to an increase in forfeiture estimates. The decrease in total general and administrative expenses per Boe was primarily due to the reduction in non-cash stock-based compensation costs noted above coupled with a slight increase in production.

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 of general and administrative expenses in the consolidated statements of operations. We earned reimbursements of $17 million and $19 million during the years ended ~~December 31, 2016 and 2015,~~respectively. The decrease in reimbursements was primarily due to decreased drilling and completion activity during 2016 and a higher average working interest in our wells drilled in 2016 as compared to 2015, partially offset by increased reimbursements attributable to more wells operated in 2016 as compared to 2015.

~~Gain (loss) on derivatives.~~~~The following table sets forth the gain (loss) on derivatives for the years ended~~ ~~December 31, 2016~~ ~~and 2015:~~

Years Ended

December 31,
(in millions)

2016

2015

Gain (loss) on derivatives:

Oil derivatives

$
(337)

$
675

Natural gas derivatives

(32)

25

Total

$
(369)

$
700

      The following table represents our net cash receipts from derivatives for the years ended December 31, 2016 and 2015:

Years Ended

December 31,
(in millions)

2016

2015

Net cash receipts from derivatives:

Oil derivatives

$
609

$
597

Natural gas derivatives


16


36

Total

$
625

$
633

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 future commodity price outlook increases between measurement periods, we will have mark-to-market losses. See Note 72 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding ~~significant judgments made in classifying financial instruments in the fair value hierarchy.~~

~~Gain (loss) on disposition of assets, net.~~ this sale.

During the ~~years~~year ended December 31, ~~2016 and 2015,~~2018, we ~~recognized a gain on disposition~~recorded other income of ~~assets of approximately $118~~$108 million ~~and a loss on disposition of assets of approximately $54 million, respectively.~~ ~~In February~~ ~~2016, we sold certain assets in our Northern Delaware Basin core area for proceeds of approximately $292 million and recognized a pre-tax gain of approximately $110 million. In December~~ ~~2015, we completed an acreage exchange with Clayton Williams Energy, Inc. that~~ ~~consolidated acres into a concentrated, operated position in our Southern Delaware Basin core area.~~ ~~We recognized a loss on disposition of assets of approximately $50 million~~primarily related to ~~the acreage exchange.~~

~~Interest expense.~~~~The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the years ended~~ ~~December 31, 2016~~ ~~and 2015:~~

Years Ended December 31,
(dollars in millions)

2016

2015

Interest expense

$
204

$
215
Capitalized interest


-

5

Interest expense, excluding impact of capitalized interest

$
204

$
220



Weighted average interest rate - credit facility

-

2.4%
Weighted average interest rate - senior notes

5.9%

5.9%
Total weighted average interest rate


5.8%

5.8%

Weighted average credit facility balance

$
-

$
195
Weighted average senior notes balance

3,182

3,350

Total weighted average debt balance

$
3,182

$
3,545

~~The decrease in the weighted average debt balance for the year ended~~ ~~December 31, 2016~~ ~~as compared to 2015 was due to the repayment of our credit facility using~~ a ~~portion~~cash distribution received from Oryx. See Note 2 of the ~~proceeds from our October 2015 equity offering~~Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and to a lesser extent, the early redemption of the $600 million outstanding principal amount of the 7.0% Notes. The decrease in interest expense was due to the overall decrease in the weighted average debt balance, partially offset by a reduction in capitalized interest.

~~Loss on extinguishment of debt.~~~~We recorded a loss on extinguishment of debt of $56 million~~Supplementary Data” for ~~the~~ ~~year ended~~ ~~December 31, 2016~~. This amount includes (i) approximately $20 million associated with the make-whole premium paid for the early extinguishment of the 6.5% Notes in December 2016, approximately $7 million of related unamortized deferred loan costs and approximately $1 million of additional interest on the 6.5% Notes through January 16, 2017, which was paid in December 2016; and (ii) $21 million associated with the make-whole premium paid for the early redemption of the 7.0% Notes in September 2016 and approximately $7 million of related unamortized deferred loan costs.

information regarding this distribution.

Income tax provisions. We recorded an income tax benefit of ~~approximately $876~~$154 million and an income tax expense of ~~approximately $31~~$603 million for the years ended December 31, ~~2016~~ 2019 and ~~2015,~~2018, respectively. The ~~shift in our~~change to income tax ~~provision is~~benefit in 2019 from income tax expense in 2018 was primarily due to ~~a significant~~the pre-tax ~~book~~ loss ~~in 2016~~during 2019 as compared to pre-tax ~~book~~ income during 2018.

For the year ended December 31, 2019, we recorded an income tax benefit of $21 million due to the decrease in ~~2015. The~~our applicable state tax rate in New Mexico as a result of the New Mexico Shelf divestiture. During the second quarter of 2019, the state of New Mexico enacted a tax law which, among other changes, amended the apportioned net operating loss carryforwards for corporations. As a result of this law change, we recorded a deferred state tax benefit of $6 million for the year ended December 31, 2019.

For the year ended December 31, 2018, the Company completed its accounting for all of the enactment-date tax effects of the TCJA and recognized an adjustment to the provisional amount recorded as of the enactment date of approximately $7 million primarily related to the deductibility of certain performance-based compensation expenses.

Our effective income tax rates were 18 percent and 21 percent for the years ended December 31, ~~2016~~2019 and ~~2015 were 38~~2018, respectively. Our effective income tax rate of 18 percent ~~and 32~~for the year ended December 31, 2019 differed from the federal statutory tax rate of 21 percent ~~respectively.~~

~~We evaluate changes~~primarily due to our industry, production, market conditions and changes in our forecasted drilling plan by tax jurisdiction. Our material state tax jurisdictions include Texas and New Mexico. In October 2016, we purchased Texas-based assets(i) nondeductible goodwill impairment; (ii) deferred benefit recognized from the decrease in the ~~Reliance Acquisition for approximately $1.7 billion, which caused a shift in our projected future apportionment from New Mexico to Texas, which has a lower statutory~~applicable state tax rate ~~than~~as a result of the New ~~Mexico. As such, we recognized an overall~~Mexico Shelf divestiture; (iii) state ~~deferred~~income taxes, including the impact of the enacted New Mexico tax ~~benefit~~law change; and (iv) research and development credits, net of ~~approximately $21 million~~unrecognized tax benefits.

Our effective tax rate of 21 percent for the year ended December 31, 2018 approximated the federal statutory tax rate of 21 percent primarily due to the benefits from (i) research and ~~approximately $9 million for 2016~~development credits, net of unrecognized tax benefits; (ii) the change in

the applicable state tax rates due to the RSP Acquisition; and ~~2015, respectively.~~

(iii) the adjustment to provisional TCJA tax effects; offset by (iv) other recurring permanent differences and state income taxes that affect our rates.

Capital Commitments, Capital Resources and Liquidity

Capital commitments.Our primary needs for cash are for (i) development, exploration and acquisition of oil and natural gas assets, (ii) midstream joint 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 and natural gas properties.Our costs incurred on oil and natural gas properties, excluding acquisitions, during theyearsendedDecember 31, ~~2017, 2016~~2019 and ~~2015~~2018 totaled ~~$1.7billion, $1.2~~$3.0 billion and ~~$1.8~~$2.6 billion, respectively. The increase from 2016 to 2017 was primarily due to our increased drilling and completion activity level during 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 included in our consolidated statements of cash flows was ~~our issuance of approximately 2.2 million shares of common stock related to our Northern Delaware Basin acquisition and~~the timing of payments. ~~Total 2017~~Our 2019 capital expenditures were primarily funded ~~in part~~ from ~~(i)~~ cash flows from operations ~~(ii) proceeds from~~and borrowings under our ~~February 2017 divestiture of ACC and (iii) our issuance of approximately 2.2 million shares of common stock related to our Northern Delaware Basin acquisition.~~

~~2018~~Credit Facility.

2020 capital ~~budget~~.budget.In February ~~2018, we announced~~2020, our ~~2018~~board of directors approved our 2020 capital budget ~~excluding acquisitions,~~ of ~~approximately $2.0 billion with expected capital spending~~up to ~~range~~$2.9 billion. We expect to spend between ~~$1.9~~$2.6 billion and ~~$2.1 billion. Our 2018 capital budget, based~~$2.8 billion on drilling and completion activity.

Dividends.On February 18, 2020, our ~~current expectations~~board of ~~commodity prices and costs,~~directors declared a cash dividend of $0.20 per share for the first quarter of 2020 that is expected to be ~~within~~paid on March 27, 2020 to stockholders of record as of February 28, 2020. Total cash dividends paid to our ~~cash flows.~~

stockholders during the year ended December 31, 2019 were $100 million. We intend to continue to pay a quarterly dividend of $0.20 in the future, however, any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant.

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 maximum aggregate dollar amount of repurchases that may be made in any quarter requires advance approval of the board of directors. 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.

We used a portion of the proceeds from the New Mexico Shelf divestiture, which closed in November 2019, to initiate share repurchases in the fourth quarter of 2019, while maintaining sufficient liquidity to fund our capital commitments and dividend payments. All additional future repurchases will require the approval of the Company’s board of directors. As of December 31, 2019, we repurchased and retired 3,300,370 shares under the program at an aggregate cost of $250 million.

Other than the customary purchase of leasehold acreage, our capital budgets are exclusive of acquisitions. We do not have a specific acquisition budget ~~since~~because 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.

Acquisitions.The following table reflects ourour expenditures for acquisitions of proved and unproved properties for the years ended December 31, ~~2017, 2016~~2019 and ~~2015:~~

Years Ended December 31,
(in millions)
2017

2016

2015

Property acquisition costs:

Proved
$
303

$
982

$
57

Unproved

905

1,154

206

Total property acquisition costs (a)
$
1,208

$
2,136

$
263

(a)
Included in the property acquisition costs above are budgeted unproved leasehold acreage acquisitions of approximately $52 million, $30 million and $69 million for the years ended December 31, 2017, 2016 and 2015, respectively. For the year ended December 31, 2017, our unbudgeted acquisitions are primarily comprised of approximately $1.1 billion of property acquisition costs related to our Midland Basin and Northern Delaware Basin acquisitions. For the year ended December 31, 2016, our unbudgeted acquisitions are primarily comprised of approximately $2.1 billion of property acquisition costs related to the Reliance Acquisition and Southern Delaware Basin acquisition.

2018:



(in millions)	Years Ended December 31,
(in millions)	2019		2018
Property acquisition costs:
Proved	$	8	$	4,136
Unproved	50		3,617
Total property acquisition costs (a)	$	58	$	7,753

(a) Included in the property acquisition costs above are budgeted unproved leasehold acreage acquisitions of $50 million and $51 million for the years ended December 31, 2019 and 2018, respectively. Our unbudgeted acquisitions during 2018 were primarily comprised of approximately $7.6 billion of property acquisition costs related to the RSP Acquisition.

Contractual obligations.We had the following contractual obligations atDecember 31, ~~2017~~:

2019:

Payments Due by Period

Less than

1 - 3

3 - 5

More than
(in millions)

Total

1 year

years

years

5 years

Long-term debt (a)

$
2,722

$
-

$
-

$
322

$
2,400
Cash interest expense on debt (b)


1,797

150

229

222

1,196
Derivative liabilities (c)

379

277

102

-

-
Asset retirement obligations (d)

141

12

13

3

113
Employment agreements with officers (e)

8

8

-

-

-
Purchase obligations (f)

256

33

84

55

84
Operating lease obligations (g)

31

10

15

5

1

Total contractual obligations

$
5,334

$
490

$
443

$
607

$
3,794

~~(a)~~See Note 9 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding future interest payment obligations on our long-term debt. The amounts included in the table above represent principal maturities only.

~~(b)~~Cash interest expense on our senior notes is estimated assuming no principal repayment until their maturity dates. Also included in the “Less than 1 year” column is accrued interest at December 31, 2017 of approximately $36 million. During 2017, we decreased our annual interest expense and extended our average maturity from six to 16 years by issuing the 2017 Notes and completing the satisfaction and discharge of the 5.5% Notes. At December 31, 2017, we had variable-rate debt ~~outstanding under our credit facility of $322 million.~~

~~(c)~~Derivative obligations represent commodity derivatives that were valued at December 31, 2017. The ultimate settlement amounts of our derivative obligations are unknown because they are subject to continuing market risk. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note 8 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our derivative obligations.

~~(d)Amounts represent costs related to expected oil and natural gas property abandonments related to proved reserves by period, net of any future accretion.~~

~~(e)~~Represents amounts of cash compensation we are obligated to pay to our officers under employment agreements assuming such employees continue to serve the entire term of their employment agreement and their cash compensation is not adjusted.

~~(f)~~Relates to purchase agreements we have entered into including daywork drilling contracts, water commitment agreements, throughput volume delivery commitments, power commitments, fixed asset commitments and maintenance commitments.

~~(g)We lease vehicles, equipment and office facilities under non-cancellable operating leases.~~



	Payments Due by Period
(in millions)	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years
Long-term debt (a)	$	4,000	$	—	$	—	$	—	$	4,000
Cash interest expense on debt (b)	2,769		235		350		350		1,834
Derivative liabilities (c)	119		112		7		—		—
Asset retirement obligations (d)	139		9		11		5		114
Employment agreements with officers (e)	10		10		—		—		—
Purchase obligations (f)	333		51		109		70		103
Lease obligations (g)	43		21		19		1		2
Total contractual obligations (h)	$	7,413	$	438	$	496	$	426	$	6,053


(a)	See Note 10 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding future interest payment obligations on our long-term debt. The amounts included in the table above represent principal maturities only.


(b)	Cash interest expense on our senior notes is estimated assuming no principal repayment until their maturity dates. Also included in the “Less than 1 year” column is accrued interest at December 31, 2019 of approximately $60 million. At December 31, 2019, we had no variable-rate debt outstanding under our Credit Facility.

(c)

Derivative obligations represent commodity derivatives that were valued at December 31, 2019. The ultimate settlement amounts of our derivative obligations are unknown because they are subject to continuing market risk. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note 9 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our derivative obligations.


(d)	Amounts represent costs related to expected oil and natural gas property abandonments, net of any future accretion.


(e)	Represents amounts of cash compensation we are obligated to pay to our officers under employment agreements assuming such employees continue to serve the entire term of their employment agreement and their cash compensation is not adjusted.


(f)	Relates to purchase agreements we have entered into including water commitment agreements, throughput volume delivery commitments, fixed and variable power commitments, sand commitment agreements and other commitments.

(g)

Relates to our operating and financing leases, including office space, office equipment, drilling rigs, field equipment and vehicles. See Note 11 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding our lease obligations. Included in the “Less than 1 year” column are the Company’s drilling rigs. Drilling rigs are short-term leases and are not capitalized under the lease standard. A portion of these costs will be reimbursed to the Company by other working interest owners.


(h)	The amounts above do not include the liability for unrecognized tax benefits. See Note 12 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.

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 and (iv) asset dispositions.~~ offerings.In February ~~2018, we announced~~2020, our ~~2018~~board of directors approved our 2020 capital budget ~~excluding acquisitions,~~ of ~~approximately $2.0 billion with expected capital spending~~up to ~~range~~$2.9 billion. We expect to spend between ~~$1.9~~$2.6 billion and ~~$2.1 billion. Our 2018~~$2.8 billion on drilling and completion activity. We expect to fund our 2020 capital budget ~~based on~~primarily with operating cash flows. We believe that our current ~~expectations of commodity prices~~cash and ~~costs, is expected~~cash equivalents, together with cash flows generated from operating activities and available borrowings under our Credit Facility, will be sufficient to ~~be within~~meet our anticipated cash ~~flows.~~

requirements for at least the next 12 months.

The following table summarizes our ~~net increase (decrease)~~changes in cash and cash equivalents for the years ended December 31, 2019 and 2018. The discussion of changes in cash and cash equivalents for the year ended December 31, 2017 ~~2016~~is included in Item 7, “Management’s Discussion and ~~2015:~~

Analysis of Financial Condition and Results of Operations” under Part II of our Annual Report on Form 10-K for the year ended December 31, 2018, which was filed with the SEC on February 20, 2019.

Years Ended December 31,
(in millions)

2017

2016

2015

Net cash provided by operating activities

$
1,695

$
1,384

$
1,530
Net cash used in investing activities


(1,719)

(2,225)

(2,602)
Net cash provided by (used in) financing activities


(29)

665

1,301
Net increase (decrease) in cash and cash equivalents

$
(53)

$
(176)

$
229

(in millions) Years Ended December 31,
2019 2018
Net cash provided by operating activities $ 2,836
$ 2,558
Net cash used in investing activities (1,993 ) (2,216 )
Net cash used in financing activities (773 ) (342 )
Net change in cash and cash equivalents $ 70
$ —

Cash flow from operating activities.The increase in operating cash flows during theyearended December 31, ~~2017~~2019 as compared to ~~2016~~2018 was primarily due to an increase in ~~oil and natural gas~~our total operating revenues of ~~approximately $951~~$441 million and ~~a decrease in cash interest expense~~an increase of ~~approximately $55~~$120 million ~~partially offset by (i) approximately $546~~due to $98 million ~~decrease in~~of settlements ~~received from~~paid on derivatives ~~(ii) approximately $88 million increase in production expense and (iii) approximately $68 million increase in production tax expense.~~

~~The decrease in operating cash flows~~ during the year ended December 31, ~~2016~~2019, as compared to ~~2015~~$218 million during 2018. The increase was ~~primarily due to a decrease~~partially offset by an increase in operating expenses on our oil and natural gas revenues of approximately $169 million and approximately $95 million of negative variances in operating assets and liabilities, partially offset by (i) approximately $70 million decrease in production expense, (ii) approximately $20 million decrease in production tax expense, (iii) an increase in operating cash flow of approximately $13 million due to a cash tax benefit of approximately $12 million for the year ended December 31, 2016 compared to cash tax expense of approximately $1 million during 2015 and (iv) a decrease in cash interest expense of approximately $11 million.

properties.

Our net cash provided by operating activities included a reduction of ~~approximately $23 million, a reduction of approximately $51~~$40 million and a benefit of ~~approximately $44~~$4 million for theyears ended December 31, ~~2017, 2016~~2019 and ~~2015~~,2018, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

Cash flow ~~used in~~from investing activities.~~During the years ended~~ ~~December 31, 2017, 2016~~Our investing activities consist primarily of drilling and ~~2015, we invested approximately $1,581 million, $1,046 million~~completion activity, acquisitions and $2,185 million, respectively, for additions to oil and natural gas properties. Additionally, we completed acquisitions of oil and natural gas properties of approximately $908 million, $1,351 million and $259 million during the years ended ~~December 31, 2017, 2016~~ ~~and 2015, respectively.~~divestitures. The primary reason for the differences in costs incurred and cash flow expenditures in 2017 was our issuance of approximately 2.2 million shares of common stock related to our Northern Delaware Basin acquisition and timing of payments. In 2016, the primary reason for the differences in costs incurred and cash flow expenditures was (i) our issuance of approximately 2.2 million shares of common stock related to our March 2016 acquisition, (ii) our issuance of approximately 3.9 million shares of common stock related to our Reliance Acquisition and (iii) timing of payments, while the difference in 2015 was primarily due to timing of payments.

The 2017 expenditures were primarily funded in part from (i) cash flows from operations, (ii) proceeds from our February 2017 divestiture of ACC and (iii) our issuance of approximately 2.2 million shares of common stock related to our Northern Delaware Basin acquisition. The 2016 expenditures were funded in part from (i) proceeds from our February 2016 divestiture, (ii) our issuance of approximately 2.2 million shares of common stock related to our March 2016 acquisition, (iii) proceeds from our August 2016 equity offering and (iv) our issuance of approximately 3.9 million shares of common stock related to our Reliance Acquisition. The 2015 expenditures were funded in part from borrowings under our credit facility and our equity offerings in 2015.

~~Cash flows used in investing activities decreased during the year ended~~ ~~December 31, 2017~~ as compared to 2016, primarily due to (i) an increase in proceeds from the disposition of assets of approximately $471 million from 2016 to 2017, (ii) a decrease of approximately $443 million for acquisitions ofon oil and natural gas properties, ~~from 2016~~including acquisitions, and cash flow expenditures is the timing of payments and the issuances of shares of common stock to ~~2017 and (iii) contributions to~~fund certain acquisitions.

For the year ended December 31, 2019, our ~~equity method investments~~net cash used in investing activities was approximately $2.0 billion, which consisted primarily of our investment of approximately ~~$56 million during 2016, while no contributions were made in 2017,~~$3.1 billion for additions to oil and natural gas properties. This was partially offset by approximately $1.3 billion of cash proceeds from asset dispositions primarily due to the New Mexico Shelf divestiture, the sale of Oryx I and the contribution of certain water infrastructure assets to an ~~increase~~entity. We used the proceeds from these and other divestitures to repay our outstanding balance under our Credit Facility. Our capital expenditures during the year ended December 31, 2019 were funded with cash flows from operations and borrowings under our Credit Facility.

For the year ended December 31, 2018, our net cash used in investing activities was approximately $2.2 billion, which consisted primarily of our investment of approximately ~~$535 million~~$2.5 billion for additions to oil and natural gas properties and $136 million of oil and natural gas property acquisitions, partially offset by (i) $361 million of proceeds received from ~~2016 to 2017.~~

the disposition of certain assets and (ii) a $148 million distribution received from Oryx, one of our equity method investments. The total distribution from Oryx was $157 million, of which $9 million represented cumulative Oryx earnings and was classified as cash flow from operating activities, while the remaining amount of $148 million was classified as cash flow from investing activities. The 2018 expenditures were primarily funded with cash flows from operations.

Cash ~~flows~~flow from financing activities.For the year endedDecember 31, 2019, our net cash used in ~~investing~~financing activities ~~decreased during~~was $773 million primarily due to $250 million of common stock repurchases under our share repurchase program, $242 million of net payments under our Credit Facility and $100 million of dividends paid on our common stock. During the year ended December 31, ~~2016 as compared to 2015, primarily due to (i) proceeds from~~2019, we decreased our book overdrafts by $159 million.

For the ~~disposition of assets of approximately $332 million during 2016, (ii) a decrease of approximately $47 million~~year ended December 31, 2018, our net cash used in amounts invested in oil and natural gas properties from 2015 to 2016, (iii) contributions to our equity method investments of approximately $56 million during 2016 compared to contributions of approximately $91 million during 2015 and (iv) approximately $61 million invested in other property and equipment during 2016 compared to approximately $67 million in 2015, partially offset by a 2016 cash outflow for funds held in escrow of $43 million related to our January 2017 asset acquisition.

~~Cash flow from~~ financing ~~activities.~~~~Below is a description of our financing activities. During 2017, 2016 and 2015 we completed the following significant capital markets activities:~~

·activities was $342 million. In ~~September 2017,~~July 2018, we issued ~~$1,800 million~~$1.6 billion in aggregate principal amount of ~~the 2017 Notes, for which we received net proceeds of approximately $1,777 million. We~~senior unsecured notes and used the net proceeds ~~from~~to redeem and cancel certain senior unsecured notes assumed in the ~~offering, together~~RSP Acquisition ("RSP Notes"). We made aggregate payments of approximately $1.2 billion to redeem and cancel the RSP Notes, including make-whole call premiums of $68 million. We also paid accrued interest of $14 million on the RSP Notes. The remaining proceeds, along with ~~cash on hand and~~ borrowings under our Credit Facility, were used to repay the $540 million of outstanding principal under RSP’s revolving credit facility, to fund the (i) Tender Offer of $1,232 million principal amount of the 5.5% Notes at a price equal to 102.934 percent of par and (ii) satisfaction and discharge of our remaining obligations of $918 million principal amount under the indentures of the 5.5% Notes at a price equal to 102.75 percent of par. The early extinguishment price included approximately $36 million associated with the premium paid for the Tender Offer, approximately $25 million for the make-whole premium paid for the early extinguishment of the 5.5% Notes and approximately $2 million for prepaid interest as part of the satisfaction and discharge.

·~~In December 2016, we issued $600~~including $1 million in ~~aggregate principal amount~~accrued interest. We also made net payments of 4.375% senior notes due 2025 at par, for which we received net proceeds of approximately $592 million. We used the net proceeds from the offering to fund the satisfaction and discharge of our obligations under the indenture of the $600$80 million ~~outstanding principal amount of the 6.5% Notes at a price equal to 103.25 percent of par. The early extinguishment price included the make-whole premium of $20 million.~~

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

·In August 2016, we issued approximately 10.4 million shares of our common stock in a public offering at $130.90 per share and received net proceeds of approximately $1.3 billion. We used a portion of the net proceeds to finance part of the cash portion of the purchase price for the Reliance Acquisition and to fund part of the early redemption of the 7.0% Notes and the remainder for general corporate purposes.

·In October 2015, we issued approximately 8.9 million shares of our common stock in a public offering at $92.50 per share and received net proceeds of approximately $794 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and used the remainder for general corporate purposes and for funding of our 2016 acquisitions.

·In March 2015, we issued 6.9 million shares of our common stock in a public offering at $107.49 per share and received net proceeds of approximately $742 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and the remainder for general corporate purposes.

·~~During 2017, we had net borrowings~~ on our ~~credit facility of $322 million.~~

·~~During 2016, we had no outstanding borrowings under our credit facility.~~

~~In April 2017, we amended our credit facility to decrease our unused lender commitments.~~ Credit Facility during 2018.

In September 2017, we elected to enter into an Investment Grade Period under our ~~credit facility,~~Credit Facility, which had the effect of releasing all collateral formerly securing ~~the credit facility.~~our Credit Facility. If the Investment Grade Period under ~~the credit facility~~our Credit Facility terminates (whether automatically or by our election), ~~the credit facility~~our 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. AtDecember 31, ~~2017,~~2019,we had unused commitments onunder our ~~credit facility~~Credit Facility of$~~1.7~~ ~~billion~~.

2.0 billion.

Advances on our ~~credit facility~~Credit Facility bear interest, at our option, based on: (i) an alternative base rate, which is equal to the highest of (a) the prime rate of JPMorgan Chase Bank (4.50 percent at December 31, 2017), (b) the federal funds effective rate plus 0.5 percent and (c) LIBOR plus 1.0 percent; or (ii) LIBOR. The credit facility’s


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


(a)	the prime rate of JPMorgan Chase Bank (4.8 percent at December 31, 2019),


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


(c)	the LIBOR plus 1.0 percent; or


(ii)	LIBOR.

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 and S&P. At our current credit ratings, LIBOR Rate Loans and Alternate Base Rate Loans bear interest margins of 150 basis points and 50 basis points per annum, respectively, and commitment fees on the unused portion of the available commitment are 25 basis points per annum.

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

Credit Facility.

Liquidity.Our principal source of liquidity is the available borrowing capacity under our ~~credit facility.~~ Credit Facility.At December 31, ~~2017~~,2019, our commitments from our bank group ~~were~~totaled $2.0 billion, all of which ~~$1.7 billion~~ was unused commitments. Subsequent to December 31, 2017, our cash position increased by approximately $250 million as a result of completing two divestitures of oil and natural gas properties located in the Southern Delaware Basin core area.

During 2017, we decreased our annual interest expense and extended the average maturity on our senior notes from six to 16 years by issuing the 2017 Notes and completing the satisfaction and discharge of the 5.5% Notes. We also note that the TCJA may have longer-term impacts on our liquidity and financial position, primarily as a result of the federal statutory tax rate changing to 21 percent from 35 percent and repeal of the corporate alternative minimum tax. Beginning January 1, 2018, our income will be subject to the new 21 percent federal statutory tax rate, which will allow us to retain a greater percentage of earnings and improve our consolidated results of operations.

unused.

Debt ~~ratings~~. ratings.We receive debt credit ratings from S&P, Moody’s and 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.

A downgrade in our credit ratings could (i) negatively impact our costs of capital and our ability to effectively execute aspects of our strategy, (ii) affect our ability to raise debt in the public debt markets, and the cost of any new debt could be much higher than our outstanding debt and (iii) negatively affect our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. Further, if we are unable to maintain credit ratings of “Ba2” or better from Moody’s and “BB” or better from S&P, the Investment Grade Period under our Credit Facility will automatically terminate and cause ~~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 adverse effect on our business, financial condition and results of operations.

As of the filing date of this Annual Report on Form 10-K, there have been no changes into our credit ~~ratings have occurred;~~ratings; however, we cannot be assured that our credit ratings will not be downgraded in the future.

Book capitalization and current ~~ratio~~. ratio.Our net book capitalization at December 31, ~~2017~~2019 was ~~$11.6~~$21.8 billion, consisting of cash and cash equivalents of $70 million, debt of $~~2.7 billion~~$4.0 billion and stockholders’ equity of $~~8.9~~ $17.8 billion. Our net book capitalization at December 31, ~~2016~~2018 was ~~$10.2~~$23.0 billion, consisting of $~~0.1 billion of cash and cash equivalents,~~ debt of $~~2.7 billion~~$4.2 billion and stockholders’ equity of $~~7.6~~ $18.8 billion. Our ratio of net debt to net book capitalization was 2318 percent and 2618 percent at December 31, ~~2017~~2019 and ~~2016,~~2018, respectively. Our ratio of current assets to current liabilities was ~~0.51~~0.89 to 1.0 at December 31, ~~2017~~2019 as compared to ~~0.75~~1.04 to 1.0 at December 31, 2016. The ratio of current assets to current liabilities at December 31, 2016 reflects the reclassification of certain prior period amounts to conform to the 2017 presentation. Both our ratio of net debt to net book capitalization and our ratio of current assets to current liabilities were impacted subsequent to December 31, 2017 by our two January 2018 divestitures.

2018.

Inflation and changes in prices.Our revenues, the value 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 we are unable to control or predict. During the year ended December 31, ~~2017,~~2019, we received an average of ~~$48.13~~$54.03per barrel of oil and ~~$3.07~~$1.74per Mcf of natural gas before consideration of commodity derivative contracts compared to ~~$39.90~~$56.22 and ~~$44.69~~$48.13per barrel of oil and ~~$2.23~~$3.40 and ~~$2.46~~$3.07per Mcf of natural gas in the years ended December 31, ~~2016~~2018 and ~~2015,~~2017, respectively. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business.

Estimates

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

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

Successful Efforts Method of Accounting

We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities. Under this method, exploration expenses, including geological and geophysical costs, lease rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment, undeveloped leases and developmental dry holes are capitalized. Exploratory drilling costs are initially capitalized, but are charged to expense if and when a well is determined not to have found proved reserves. Generally, a gain or loss is recognized when producing fields are sold. This accounting method may yield significantly different results than the full cost method of accounting.

The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that proved reserves have been discovered may take considerable time, and requires both judgment and application of industry experience. The evaluation of oil and natural gas leasehold acquisition costs included in unproved properties requires management’s judgment to estimate the fair value of such properties. Drilling activities in an area by other companies may also effectively impair our leasehold positions.

Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually significant non-producing properties or projects are periodically assessed for impairment of value ~~by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects.~~

Depletion of capitalized drilling and development costs of oil and natural gas properties is computed using the unit-of-production method on total estimated proved developed oil and natural gas reserves. Depletion of producing leaseholds is based on the unit-of-production method using our total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. Service properties, equipment and other assets are depreciated using the straight-line method over estimated useful lives of two to 39 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated depreciation and depletion are eliminated from the accounts and the resulting gain or loss is recognized.

Oil and Natural Gas Reserves and Standardized Measure of Discounted Net Future Cash Flows

This report presents estimates of our proved reserves as of December 31, ~~2017,~~2019, which have been prepared and presented in accordance with SEC guidelines. The pricing that was used for estimates of our reserves as of December 31, ~~2017~~2019 was based on the 12-month unweighted average of the first-day-of-the-month WTI posted price of ~~$47.79~~$52.19per Bbl for oil and Henry Hub spot natural gas price of ~~$2.98~~$2.58per MMBtu for natural gas.

Our independent engineers and technical staff prepare the estimates of our oil and natural gas reserves and associated future net cash flows. Even though our independent engineers and technical staff are knowledgeable and follow authoritative guidelines for estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve estimates. Reserve estimates are updated at least annually and consider recent production levels and other technical information about each field. Periodic revisions to the estimated reserves and future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly alter future depletion and result in impairment of long-lived assets that may be material.

It should not be assumed that the Standardized Measure included in this report as of December 31, ~~2017~~2019 is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the ~~2017~~2019 Standardized Measure on the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See “Item 1A. Risk Factors” and “Item 2. Properties” for additional information regarding estimates of proved reserves.

Our estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, reducing future earnings. Such a decline may result from lower commodity prices,

which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of our proved properties for impairment.

Asset Retirement Obligations

There are legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and the normal operation of a long-lived asset. The primary impact of this relates to oil and natural gas wells on which we have a legal obligation to plug and abandon. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and, generally, a corresponding increase in the carrying amount of the related long-lived asset. The determination of the fair value of the liability requires us to make numerous judgments and estimates, including judgments and estimates related to future costs to plug and abandon wells, future inflation rates and estimated lives of the related assets. When the judgments used to estimate the initial fair value of the asset retirement obligation change, an adjustment is recorded to both the obligation and the carrying amount of the related long-lived asset. Historically, there have been no significant revisions to our initial estimates once future results became known. See Note 56 of the Notes to ~~the~~ Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our asset retirement obligations.

Impairment of Long-Lived Assets

All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may be greater than management’s estimates of its future net cash flows, including cash flows from proved reserves, risk-adjusted probable and possible reserves, and integrated assets. If the carrying value of the long-lived assets exceeds the sum of estimated undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair value and the carrying value of the assets. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates, cash flows from integrated assets and other factors. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimated quantities of oil and natural gas reserves. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. ~~Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded.~~ AtDecember 31, ~~2017,~~2019, our estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a ~~2018~~2020 price of ~~$59.55~~$58.83 per barrel of oil decreasing to a ~~2024~~2023 price of ~~$51.82~~$51.31 per barrel of oil ~~marginally recovering~~then rising to a ~~2025~~2026 price of ~~$51.83~~$52.57 per barrel of oil. ~~Similarly, natural~~Natural gas prices ranged from a ~~2018~~2020 price of ~~$2.84~~$2.29 per Mcf of natural gas ~~decreasing~~increasing to a ~~2019~~2026 price of ~~$2.81 per Mcf then rising to a 2025 price of $2.99~~$2.55 per Mcf of natural gas. Both oil and natural gas commodity prices for this purpose were held flat after ~~2025.~~

2026.

$29 $147 million, $60 $35 million and $35 $27 million, respectively, related to abandoned and expiring acreage, which is included in exploration and abandonments expensein the accompanying consolidated statements of operations.

Valuation of Stock-Based Compensation

In accordance with GAAP, we calculate the fair value of stock-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. We utilize (i) the average of the high and low stock price on the date of grant for the fair value of restricted stock awards and (ii) the Monte Carlo simulation method for the fair value of performance unit awards. The significant assumptions used in these models include expected volatility, expected term, risk-free interest rate, forfeiture rate, dividends, and the probability of meeting performance targets. Each of these valuation methods were chosen as management believes they give the best estimate of fair value for the respective stock-based awards. See Note 67 of the Notes to ~~the~~ Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information regarding our stock-based compensation.

Valuation of Business Combinations

In connection with a purchase business combination, the acquiring company must record assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes must be recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of purchase price over amounts assigned to assets and liabilities is recorded as goodwill. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the value attributed to assets acquired and liabilities assumed.

In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions related to the estimated fair values assigned to proved and unproved oil and natural gas properties and integrated assets. To estimate the fair values of these properties, we utilize estimates of oil and natural gas reserves. We make future price assumptions to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subject to additional project-specific risking factors. To estimate the fair value of unproved properties, we apply

risk-weighting factors of the future net cash flows of unproved reserves, or we may evaluate acreage values through recent market transactions in the area.

Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in a higher depletion expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded. Historically, we have had no material revisions to valuations of business combinations once ~~actual results became known.~~

Accounting and Valuation of Nonmonetary Transactions

In connection with nonmonetary transactions, which include exchanges of producing and non-producing assets, we must evaluate the transaction to determine appropriate accounting treatment. In general, the basic principle of accounting for nonmonetary transactions is based on the fair values involved, which is the same basis used in monetary transactions and results in the recognition of gains and losses. However, certain nonmonetary transactions meet criteria that require modification of the basic principle that necessitate recording values based on historical book value. We determine the treatment of nonmonetary transactions based on the individual facts and circumstances of each transaction. In cases where nonmonetary transactions are recorded at fair value, we make various assumptions. The most significant assumptions are related to the estimated fair values assigned to proved and unproved oil and natural gas properties, similar to our valuation of the fair value of oil and natural gas assets acquired during a business combination described above. Any resulting difference between the fair value of the assets involved and their carrying value is recorded as a gain or loss in the consolidated statement of operations.

Estimated fair values assigned to assets exchanged can have a significant effect on our results of operations in the future. If future commodity prices or reserves quantities are lower than those originally used to determine fair value or if future operating expenses or development costs are higher than those originally used to determine fair value, we would record an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.

Impairments of Goodwill

Goodwill is assessed for impairment on an annual basis, or more frequently if indicators of impairment exist. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, is performed as of July 1 of each year. As we operate as a single operating segment and a single reporting unit, we evaluate goodwill for impairment based on an evaluation of the fair value of the company as a whole. The fair value of the reporting unit is our enterprise value (combined market capitalization of our equity plus a control premium, and the fair value of our long-term debt). There are multiple valuation methodologies available to us in determining the fair values; however, given that we are one reporting unit, we use quoted market prices in active markets as the basis for our measurement as we believe they are the best evidence of fair value. There is considerable judgment involved in estimating fair values, particularly in determining the control premium. To establish a reasonable control premium, we consider the premiums paid in recent market acquisitions and analyze current industry, market and economic conditions along with other factors or available information specific to our business. Deteriorating industry, market and economic conditions could negatively impact our control premium and our enterprise value, which could lead to an impairment of our goodwill balance.

As discussed in Note 5 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data,” in August 2019, we entered into a definitive agreement to sell our assets in the New Mexico Shelf. We classified these assets as held for sale at August 29, 2019. We allocated $81 million of goodwill to this disposal group, all of which we impaired. In addition, we performed an impairment test at September 30, 2019 due to declines in our market capitalization and at December 31, 2019 due to declines in observed control premiums. The fair value of the reporting unit at September 30, 2019 exceeded the carrying value of our net assets. However, during the fourth quarter of 2019, our fair value declined further resulting in a $201 million goodwill impairment charge at December 31, 2019.

It is reasonably possible that the estimates of our enterprise value may change in the future and result in the need to impair goodwill. Currently, the primary factors that may negatively affect our enterprise value are the continued depressed level of our stock price and estimated control premium we use in the fair value of our reporting unit. We use an average stock price over a determined period to estimate the fair value of our reporting unit, which we believe removes the impact of short-term market fluctuations. We used an average stock price of $72.23 in determining our market capitalization at December 31, 2019. In addition, our control premium is based on the estimated median control premium of transactions involving companies in our industry. Further declines in our average stock price and/or in our estimated control premium could result in additional impairments of goodwill. Many factors affecting our stock price are beyond our control and we cannot predict their potential effects on the price of our common stock. In addition, stock markets in general can experience considerable price and volume fluctuations. Other assumptions such as the control premium and the value of our long-term debt will likely change in the future, and these and other assumptions may worsen or partially mitigate some of the effects of a reduction in our average stock price. As a result, we are unable to predict with certainty whether or not a decline in our stock price alone will or will not cause us to recognize an impairment charge or the magnitude of such impairment charge.

See Notes 2 and 4 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information regarding goodwill.

Litigation and Environmental Contingencies

We make judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the amount of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and regulations, developing information relating to the extent and nature of site contamination and improvements in technology. A liability is recorded for these types of contingencies if we determine the loss to be both probable and reasonably estimable. If we are unable to reasonably estimate an amount but we are able to estimate a range of reasonably possible amounts, then the low end of the range is recorded. See Notes 2 and 11 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information regarding our commitments and contingencies.

Valuation of Financial ~~Derivative Instruments~~

Derivatives

In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our oil and natural gas, we enter into commodity price hedging arrangements with respect to a portion of our expected production. In

addition, we have used derivative instruments in connection with acquisitions and certain price-sensitive projects. Management exercises significant judgment in determining the types of instruments to be used, production volumes to be hedged, prices at which to hedge and the counterparties’ creditworthiness. All derivative instruments are reflected at fair value in our consolidated balance sheets.

Our open commodity derivative instruments were in a net liability position with a fair value of ~~$379~~$102 million at December 31, ~~2017.~~2019. In order to determine the fair value at the end of each reporting period, we compute discounted cash flows for the duration of each commodity derivative instrument using the terms of the related contract. Inputs consist of published forward commodity price curves as of the date of the estimate. We compare these prices to the price parameters contained in our hedge contracts to determine estimated future cash inflows or outflows. We then discount the cash inflows or outflows using a combination of published LIBOR rates and Eurodollar futures rates. The fair values of our commodity derivative assets and liabilities include a measure of credit risk based on average published yields by credit rating.

Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur. For the year ended December 31, ~~2017,~~2019, we reported a$~~126~~ 895 million loss on commodity derivative instruments.

We compare our estimates of the fair values of our commodity derivative instruments with those provided by our counterparties. There have been no significant differences.

Income Taxes

On December 22, 2017, the President of the United States signed the TCJA into law, which enacted significant changes to the federal income tax laws. According to ASC 740, “Income Taxes,” a company is required to record the effects of an enacted tax law or rate change in the period of enactment. Based on the comprehensiveness of TCJA and the challenges faced by calendar year-end registrants to complete the accounting for the income tax effects of the TCJA in the period of enactment, the SEC issued SAB 118 “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” which ~~allows~~allowed companies to report provisional amounts when based on reasonable estimates and to adjust these amounts during a measurement period of up to one year.

Although we have performed an initial assessment of the TCJA, we recognize it is a comprehensive tax bill and the ultimate impacts may differ from our initial estimates due to changes in our interpretations as a result of additional regulatory guidance that may become available. As such, we have

We elected to apply SAB 118 and ~~have~~ recorded provisional amounts of our income tax balances in our consolidated financial ~~statements.~~statements at December 31, 2017. We ~~will continue to monitor new tax law interpretations, which could potentially affect the measurement of these balances or potentially give rise to revised deferred tax amounts. We have~~ calculated our best estimate of the impact of the TCJA, including the federal statutory tax rate change noted below, in our ~~year-end~~2017 income tax provision in accordance with our understanding of the TCJA and ~~guidance available as of the date of this filing and as~~recorded a ~~result have recorded~~ $398 million ~~as a~~ decrease to our income tax provision at December 31, 2017. The provisional amount related to the re-measurement of certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the ~~future~~future. At December 31, 2018, the Company completed its accounting for all of the enactment-date tax effects of the TCJA and recognized an adjustment of $7 million to the provisional amount recorded at December 31, 2017. This adjustment was ~~$398 million.~~

primarily related to the deductibility of certain performance-based compensation based on additional available regulatory and interpretive guidance.

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

Our provision for income taxes includes both federal and state taxes of the jurisdictions in which we operate. We estimate our overall tax rate using a combination of the enacted federal statutory tax rate, which decreased from 35 percent to 21 percent effective

January 1, 2018 as a result of the TCJA, and a blend of enacted state tax rates. Acquisitions or dispositions of assets and changes in our drilling plan by tax jurisdiction could change the apportionment of our state taxes, which would impact our overall tax rate.

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to our deferred tax liability and will affect our effective tax rate in the period it is recognized. The ~~TCJA also repealed the corporate AMT for~~assessment of potential uncertain tax ~~years beginning after December 31, 2017,~~positions requires a significant amount of judgment and ~~provides that existing AMT credit carryovers~~ are ~~refundable beginning with the 2018 tax year. We have approximately $10 million of AMT credit carryovers that are expected to be fully refunded by 2022.~~

reviewed and adjusted on a periodic basis.

Our federal and state income tax returns are not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities and tax attributes, which are based on numerous judgments and assumptions inherent in the determination of ~~future~~ taxable income, at the end of each ~~period as well as the effects of tax rate changes and tax credits.~~period. Adjustments related to these estimates are recorded in our tax provision in the period in which we finalize our income tax returns. Historically, we have had no significant changes as a result of filing our tax returns.Material changes to our tax accruals and uncertain tax positions may occur in the future based on audits, changes in legislation or resolutionof pending matters.

See Note 1112 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and ~~Supplemental~~Supplementary Data” for additional information regarding our current year income tax ~~expense and~~benefit, deferred tax ~~balances.~~

balances and uncertain tax positions.

In May 2014, 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~~adopted.See Note 2 of the ~~Effective Date,” which deferred the effective date of ASU No. 2014-09 by one year. The~~Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding new standard is now effective for annual reporting periods beginning after December 15, 2017. We will 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 completed our internal evaluation of the adoption of this standard, which included a review of revenue-related contracts with customers and the application of the new revenue recognition model against those contracts and have updated our revenue recognition policy ~~and our related internal control documentation, processes and controls to conform to the new standard. We will also expand our revenue recognition related disclosures. Including those changes previously discussed, this new guidance will~~accounting pronouncements issued but not ~~have a material impact on our 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. We do not plan to early adopt the standard. We enter into lease agreements to support our operations. These agreements are for leases on assets such as office space, vehicles, field services, well equipment and drilling rigs. We are substantially complete with the process of reviewing and determining the contracts to which this new guidance applies. We are currently enhancing our accounting systems in order to track and calculate additional information necessary for adoption of this standard. We believe this new guidance will have a moderate impact to our 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 No. 2016-13, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. This guidance is effective for fiscal years beginning after December 15, 2019, and early adoption is allowed as early as fiscal years beginning after December 15, 2018. We do not believe this new guidance will have a material impact 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 output. This new guidance is effective for annual periods beginning after December 15, 2017, and early adoption is allowed. We do not believe this new guidance will have a material impact on our consolidated financial statements.

yet adopted.

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 December 31, ~~2017,~~2019, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit. We do not enter into derivative or other financial instruments for speculative or trading purposes.

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

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

We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set-off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 89 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our derivative activities.

Commodity price risk. We are exposed to market risk as the prices of our commodities are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of our commodities, we have entered into, and may in the future enter into, additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Our commodity price risk management arrangements are recorded at fair value and thus changes to the future commodity prices will have an impact on ~~net income.~~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 average commodity prices atfor the years ended December 31, ~~2017:~~

2019 and 2018:

2017

2016

Increase of

Decrease of

Increase of

Decrease of

$5.00 per Bbl and

$5.00 per Bbl and

$5.00 per Bbl and

$5.00 per Bbl and
(in millions)
$0.50 per MMBtu

$0.50 per MMBtu

$0.50 per MMBtu

$0.50 per MMBtu

��

Gain (loss):

Oil derivatives
$
(290)

$
290

$
(216)

$
216

Natural gas derivatives

(37)

37

(33)

33

Total
$
(327)

$
327

$
(249)

$
249



(in millions)	2019					2018
(in millions)	Increase of $5.00 per Bbl and $0.50 per MMBtu			Decrease of $5.00 per Bbl and $0.50 per MMBtu		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	$	(369	)	$	369	$	(369	)	$	370
Natural gas derivatives	(82		)	82		(37		)	37
Total	$	(451	)	$	451	$	(406	)	$	407

Our commodity price risk management arrangements expose us to risk of non-performance by the counterparty to the agreements. Our exposure to the risk of non-performance is diversified over large, investment grade financial institutions. In addition, we have master netting agreements with the counterparties that allow for offsetting payables against receivables from separate contracts with the same counterparty. At December 31, ~~2017,~~2019, the counterparties to our commodity price risk management arrangements include ~~thirteen~~14 financial institutions, ~~all~~the majority of which are lenders tounder our ~~credit facility.~~Credit Facility. Risk of non-performance is considered when determining the fair value of our commodity price risk management arrangements. The fair value adjustment for non-performance risk was immaterial at December 31, ~~2017.~~2019. If at any point a counterparty’s financial position deteriorates, such deterioration could have a significant impact on the collectability of that counterparty’s related commodity price risk management arrangement asset.

At December 31, 2017, we had (i) oil price swaps that settle on a monthly basis covering future oil production from January 1, 2018 through December 31, 2019 and (ii) oil basis swaps covering our Midland to Cushing basis differential from January 1, 2018 to December 31, 2019. See Note 89 and Note 13 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information ~~on the commodity~~regarding our significant derivative ~~instruments.~~counterparties.

At December 31, 2019, we had (i) oil price swaps covering future oil production from January 1, 2020 through December 31, 2021 and (ii) oil basis swaps covering our Midland to Cushing basis differential from January 1, 2020 to December 31, 2021. The ~~average~~ NYMEX oil price ~~for the year ended~~at December 31, ~~2017,~~2019 was ~~$50.97~~$61.06 per Bbl. At February ~~16, 2018,~~14, 2020, the NYMEX oil price was ~~$61.68~~$52.05 per Bbl.

AtDecember 31, ~~2017~~,2019, we had (i) natural gas price swaps that settle on a monthly basis covering future natural gas production from January 1, ~~2018~~ 2020to December 31, ~~2019. See Note 8 of the Notes~~2021 and (ii) natural gas basis swaps covering our El Paso Permian to ~~Consolidated Financial Statements included in “Item 8. Financial Statements~~Henry Hub and ~~Supplementary Data” for additional information on our commodity derivative instruments.~~

WAHA to Henry Hub basis differentials from January 1, 2020 to December 31, 2021. The ~~average~~ NYMEX natural gas price ~~for the~~ ~~year~~ ~~ended~~ atDecember 31, ~~2017~~2019was$~~3.02~~2.19per MMBtu. AtFebruary ~~16, 2018,~~14, 2020,the NYMEX natural gas price was$~~2.56~~ 1.84per MMBtu.

~~A decrease~~

An increase in the average forward NYMEX oil and natural gas prices ~~below~~above those at December 31, ~~2017~~2019 would ~~decrease~~increase the fair value liability of our commodity derivative contracts from their recorded balances at December 31, ~~2017.~~2019. Changes in the recorded fair value of our commodity derivative contracts are marked to market through earnings as gains or losses. The potential ~~decrease~~increase in our fair value liability 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 December 31, ~~2017~~2019 would ~~increase~~decrease the fair value liability of our commodity derivative contracts from their recorded balances at December 31, ~~2017.~~2019. The potential ~~increase~~decrease in our fair value liability 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.

We recorded a loss on derivatives of ~~$126~~$895 million for the year ended December 31, ~~2017,~~2019, compared to a ~~loss~~gain of ~~$369~~$832 million for the year ended December 31, ~~2016.~~2018. The largest factor in the change from ~~2016~~2018 to ~~2017~~2019 related 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 during the year endedDecember 31, ~~2017~~. 2019. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the year endedDecember 31, 2019:



(in millions)	Commodity Derivative Instruments Net Assets (Liabilities)
Fair value of contracts outstanding December 31, 2018	$	695
Changes in fair values (a)	(895		)
Contract maturities	98
Fair value of contracts outstanding December 31, 2019 (b)	$	(102	)

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

See Note 8 9 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our derivative instruments. ~~The following table reconciles the changes that occurred in the fair values of our derivative instruments during the year ended~~ ~~December 31, 2017~~:


		~~Commodity Derivative~~
		~~Instruments~~
~~(in millions)~~		~~Net Liabilities (a)~~

~~Fair value of contracts outstanding at December 31, 2016~~			$	~~(174)~~
	~~Changes in fair values (b)~~			~~(126)~~
	~~Contract maturities~~			~~(79)~~
~~Fair value of contracts outstanding at December 31, 2017~~			$	~~(379)~~


~~(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.~~

Interest rate risk. Our exposure to changes in interest rates relates primarily to debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. To reduce our exposure to changes in interest rates we may, in the future, enter into interest rate risk management arrangements for a portion of our outstanding debt. The agreements that we have entered into generally have the effect of providing us with a fixed interest rate for a portion of our variable-rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We had no outstanding interest rate derivative contracts at December 31, 2019. 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 $322 million~~ outstanding under our ~~credit facility~~Credit Facility at December 31, ~~2017. The impact of a one percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $3 million.~~

2019.

~~Our consolidated financial statements and supplementary data are included in this report beginning on page F-1.~~

~~We had no changes in, and no disagreements with, our accountants on accounting and financial disclosure.~~

~~Item 9A. Controls and Procedures~~

~~Evaluation of Disclosure Controls and Procedures~~. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this 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 ~~December 31, 2017~~ ~~at the reasonable assurance level.~~

~~Management’s Report on Internal Control over Financial Reporting.~~ T~~he management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company~~’~~s internal control over financial reporting is a process designed under the supervision of the Company~~’~~s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company~~’~~s financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.~~

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements in a timely manner. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

~~As of December 31, 2017, management assessed the effectiveness of the Company~~’s internal control over financial reporting based on the criteria established in “Internal Control - Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that the Company maintained effective internal control over financial reporting at December 31, 2017.

Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this annual report on Form 10-K, has issued its report on the effectiveness of the Company’~~s internal control over financial reporting at December 31, 2017. The report, which expresses an unqualified opinion on the effectiveness of the Company~~’~~s internal control over financial reporting at December 31, 2017, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”~~

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

~~REPORT OF INDEPENDENT REGISTERED PUBLIC~~~~ACCOUNTI~~~~NG FIRM~~

~~Board of Directors and Stockholders~~

~~Concho Resources Inc.~~

~~Opinion on internal control over financial reporting~~

We have audited the internal control over financial reporting of Concho Resources Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2017, based on criteria established in the 2013 ~~Internal Control—Integrated Framework~~ issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 ~~Internal Control—Integrated Framework~~ ~~issued by COSO.~~

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2017, and our report dated February 21, 2018 expressed an unqualified opinion on those financial statements.

~~Basis for opinion~~

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

~~Definition and limitations of internal control over financial reporting~~

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

~~/s/ GRANT THORNTON LLP~~

~~Oklahoma City, Oklahoma~~

~~February 21, 2018~~

~~Item 9B. Other Information~~

~~None.~~

~~PART III~~

Item 10 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2017.

~~Code of Ethics.~~ Our board of directors has adopted a financial code of ethics applicable to our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and other senior financial officers, and a code of business conduct and ethics applicable to our directors, officers and employees, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE (the “Codes”). The Codes can be found on our website located at ~~www.concho.com~~. We intend to disclose future amendments to certain provisions of the Codes, and waivers of the Codes granted to executive officers and directors, on our website within four business days following the date of the amendment or waiver.

Item 11 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2017.

~~Equity compensation plans.~~ At December 31, 2017, a total of 10,500,000 shares of common stock were authorized for issuance under our equity compensation plan. In the table below, we describe certain information about these shares and the equity compensation plan which provides for their authorization and issuance. Included in column (1) are (i) unvested performance units at the maximum potential payout percentage and (ii) performance units relating to the performance period that ended on December 31, 2017 at the actual payout percentage of 300 percent. You can find descriptions of our stock incentive plan under Note 6 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

(1)

(2)

(3)

Number of

Number of securities

securities to be

Weighted

remaining available

issued upon

average

for future issuance

exercise of

exercise

under equity

outstanding

price of

compensation plans

options, warrants

outstanding

(excluding securities
Plan category
and rights

options

reflected in column (1))

Equity compensation plan approved by the security holders (a)

1,189,773

$
-
(c)
2,126,731
Equity compensation plan not approved by the security

holders (b)

-

$
-

-
Total

1,189,773

2,126,731

(a)

2015 Stock Incentive Plan. See Note 6 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

(b)

None.
(c)

Performance unit awards do not have an exercise price and, therefore, have been excluded from the weighted average exercise price calculation in column (2).

~~The remaining information required by~~ Item 12 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2017.

Item 13 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2017.

Item 14 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2017.

~~PART IV~~

~~Item 15.~~~~Exhibits, Financial Statement Schedules~~

~~(a)~~~~Listing of Financial Statements~~

~~Financial Statements~~

~~The following consolidated financial statements are included in “Item 8.~~ ~~Financial Statements and Supplementary Data”:~~

~~Report of Independent Registered Public Accounting Firm~~

~~Consolidated Balance Sheets at December 31, 2017 and 2016~~

~~Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015~~

~~Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2017, 2016 and 2015~~

~~Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015~~

~~Notes to Consolidated Financial Statements~~

~~Unaudited Supplementary Data~~

~~(b)~~~~Exhibits~~

~~The exhibits to this report required to be filed pursuant to Item 15(b) are listed below and in the “Index to Exhibits” attached hereto.~~

~~(c)~~~~Financial Statement Schedules~~

~~No financial statement schedules are required to be filed as part of this report or they are inapplicable.~~

~~Exhibits~~

~~Exhibit~~

~~Number~~ ~~Description~~

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

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

~~4.1~~ ~~Specimen Common Stock Certificate (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~~ Senior Indenture, dated September 18, 2009, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on September 22, 2009, and incorporated herein by reference).

~~4.3~~ Second Supplemental Indenture, dated November 3, 2010, between Concho Oil & Gas LLC, COG Holdings LLC, COG Exchange Properties LLC, Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.4 to the Post-Effective Amendment to the Company’s Registration Statement on Form S-3 on December 7, 2010, and incorporated herein by reference).

~~4.4~~ Fifth Supplemental Indenture, dated December 12, 2011, between COG Production LLC, COG Acreage LP, Delaware River SWD, LLC, Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.7 to the Company’s Annual Report on Form 10-K on February 24, 2012, and incorporated herein by reference).

~~4.5~~ Sixth Supplemental Indenture, dated March 12, 2012, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).

~~4.6~~ Seventh Supplemental Indenture, dated August 17, 2012, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on August 17, 2012, and incorporated herein by reference).

~~4.7~~ Tenth Supplemental Indenture, dated December 28, 2016, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on December 28, 2016, and incorporated herein by reference).

~~4.8~~ 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 4.1 to the Company’s Current Report on Form 8-K on September 26, 2017, and incorporated herein by reference).

~~4.9~~ Thirteenth 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 4.2 to the Company’s Current Report on Form 8-K on September 26, 2017, and incorporated herein by reference).

~~4.10~~ ~~Form of 4.375% Senior Notes due 2025 (Annex A, Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on December 28, 2016, and incorporated herein by reference).~~

~~4.11~~ ~~Form of 3.75% Senior Notes due 2027 (Annex A, Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on September 26, 2017, and incorporated herein by reference).~~

~~4.12~~ ~~Form of 4.875% Senior Notes due 2047 (Annex A, Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on September 26, 2017, and incorporated herein by reference).~~

~~10.1~~ ** Form of Performance Unit Award Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 4, 2013, and incorporated herein by reference).

~~10.2~~ ** Concho Resources Inc. 2015 Stock Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 5, 2015, and incorporated herein by reference).

~~10.3~~ ** Form of Nonstatutory Stock Option Agreement (filed as Exhibit 10.16 to the Company’s Annual Report on Form 10-K on March 28, 2008, and incorporated herein by reference).

~~10.4~~ ** Form of Restricted Stock Agreement (for officers) (filed as Exhibit 10.1 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).

~~10.5~~ ** Form of Restricted Stock Agreement (for non-employee directors) (filed as Exhibit 10.18 to the Company’s Annual Report on Form 10-K on March 28, 2008, and incorporated herein by reference).

~~10.6~~ ** Employment Agreement, dated December 19, 2008, between Concho Resources Inc. and Timothy A. Leach (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on December 19, 2008, and incorporated herein by reference).

~~10.7~~ ** Employment Agreement, dated December 19, 2008, between Concho Resources Inc. and E. Joseph Wright (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on December 19, 2008, and incorporated herein by reference).

~~10.8~~ ** Employment Agreement, dated November 5, 2009, between Concho Resources Inc. and C. William Giraud IV (filed as Exhibit 10.18 to the Company’s Annual Report on Form 10-K on February 26, 2010, and incorporated herein by reference).

~~10.9~~ ** Employment Agreement, dated March 19, 2014, between Concho Resources Inc. and Jack F. Harper (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on March 24, 2014, and incorporated herein by reference).

~~10.10~~ ** Form of First Amendment to Employment Agreement between Concho Resources Inc. and each of Messrs. Leach, Giraud and Wright (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q on May 6, 2011, and incorporated herein by reference).

~~10.11~~ ** Form of Indemnification Agreement between Concho Resources Inc. and each of the officers and directors thereof (filed as Exhibit 10.24 to the Company’s Registration Statement on Form S-1 on April 24, 2007, and incorporated herein by reference).

~~10.12~~ ** Indemnification Agreement, dated February 27, 2008, by and between Concho Resources Inc. and William H. Easter III (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 4, 2008, and incorporated herein by reference).

~~10.13~~ ** Indemnification Agreement, dated November 5, 2009, by and between Concho Resources Inc. and Mark B. Puckett (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on November 12, 2009, and incorporated herein by reference).

~~10.14~~ ** Indemnification Agreement, dated November 5, 2009, by and between Concho Resources Inc. and C. William Giraud (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on November 12, 2009, and incorporated herein by reference).

~~10.15~~ ** Form of Director and Officer Indemnification Agreement between Concho Resources Inc. and each of Messrs. Surma and Harper (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 24, 2014, and incorporated herein by reference).

~~10.16~~ ** Indemnification Agreement, dated January 10, 2012, between Concho Resources Inc. and Gary A. Merriman (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 12, 2012, and incorporated herein by reference).

~~10.17~~ ** Form of Indemnification Agreement, dated March 27, 2017, between Concho Resources Inc. and Susan J. Helms (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 28, 2017, and incorporated herein by reference).

~~10.18~~ ** Retirement Agreement, dated May 17, 2017, by and between Concho Resources Inc. and E. Joseph Wright (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on May 19, 2017, and incorporated herein by reference).

~~10.19~~ ** Performance Unit Award Agreement, ~~dated January 2, 2018, by and between Concho Resources Inc. and E. Joseph Wright~~ ~~(filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 4, 2018, and incorporated herein by reference).~~

~~10.20~~**Restricted Stock Agreement, dated January 2, 2018, between Concho Resources Inc. and E. Joseph Wright (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on January 4, 2018, and incorporated herein by reference).

~~10.21~~ Second Amended and Restated Credit Agreement, dated as of May 9, 2014, among Concho Resources Inc., the lenders party thereto, JPMorgan Chase Bank, N.A., as administrative agent, and the co-syndication agents and co-documentation agents named therein (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q on May 12, 2014, and incorporated herein by reference).

~~10.22~~ First Amendment to Second Amended and Restated Credit Agreement, dated as of April 8, 2015, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 9, 2015, and incorporated herein by reference).

~~10.23~~ ~~Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 12, 2017, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as~~

~~administrative agent (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q on August 3, 2017, and incorporated herein by reference).~~

~~10.24~~ Purchase and Sale Agreement, dated August 15, 2016, by and among COG Operating LLC, as purchaser, Concho Resources Inc., as purchaser parent, and Reliance Energy, Inc., Reliance Exploration, Ltd., Reliance Energy-WA, LLC, Reliance Energy-GF, LLC and the other persons named as sellers therein, as the seller parties (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on August 16, 2016, and incorporated herein by reference).

~~10.25Securities Purchase Agreement, dated January 19, 2017, between COG Operating LLC, as seller, and Plains Pipeline, L.P., as purchaser (filed as Exhibit 10.1~~ ~~to the Company’s Quarterly Report on Form 10-Q on May 4, 2017, and incorporated herein by reference).~~

~~12.1~~ ~~(a)~~ ~~Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Stock Dividends.~~

~~21.1~~ ~~(a)~~ ~~Subsidiaries of Concho Resources Inc.~~

~~23.1~~ ~~(a)~~ ~~Consent of Grant Thornton LLP.~~

~~23.2~~ ~~(a)~~ ~~Consent of Netherland, Sewell & Associates, Inc.~~

~~23.3~~ ~~(a)~~ ~~Consent of Cawley, Gillespie & Associates, Inc.~~

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

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

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

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

~~99.1~~ ~~(a)~~ ~~Netherland, Sewell & Associates, Inc. Reserve Report.~~

~~99.2~~ ~~(a)~~ ~~Cawley, Gillespie & Associates, Inc. Reserve Report.~~

~~101.INS (a)~~ ~~XBRL Instance Document.~~

~~101.SCH (a)~~ ~~XBRL Schema Document.~~

~~101.CAL (a)~~ ~~XBRL Calculation Linkbase Document.~~

~~101.DEF (a)~~ ~~XBRL Definition Linkbase Document.~~

~~101.LAB (a)~~ ~~XBRL Labels Linkbase Document.~~

~~101.PRE (a)~~ ~~XBRL Presentation Linkbase Document.~~

~~(a) Filed herewith.~~

~~(b) Furnished herewith.~~

** Management contract or compensatory plan or agreement

~~None.~~

~~SIGNATURES~~

Pursuant to the requirements of Section 13 or 15(d) 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:~~	~~February 21, 2018~~	By	~~/s/ Timothy A. Leach~~

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

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


~~Signature~~	~~Title~~	~~Date~~

~~/s/ TIMOTHY A. LEACH~~	~~Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)~~	~~February 21, 2018~~
~~Timothy A. Leach~~

~~/s/ JACK F. HARPER~~	~~President and Chief Financial Officer (Principal Financial Officer)~~	~~February 21, 2018~~
~~Jack F. Harper~~

~~/s/ BRENDA R. SCHROER~~	~~Senior Vice President, Chief Accounting Officer and Treasurer (Principal Accounting Officer)~~	~~February 21, 2018~~
~~Brenda R. Schroer~~

~~/s/ STEVEN L. BEAL~~	~~Director~~	~~February 21, 2018~~
~~Steven L. Beal~~

~~/s/ TUCKER S. BRIDWELL~~	~~Director~~	~~February 21, 2018~~
~~Tucker S. Bridwell~~

~~/s/ WILLIAM H. EASTER III~~	~~Director~~	~~February 21, 2018~~
~~William H. Easter III~~

~~/s/ SUSAN J. HELMS~~	~~Director~~	~~February 21, 2018~~
~~Susan J. Helms~~

~~/s/ GARY A. MERRIMAN~~	~~Director~~	~~February 21, 2018~~
~~Gary A. Merriman~~

~~/s/ RAY M. POAGE~~	~~Director~~	~~February 21, 2018~~
~~Ray M. Poage~~

~~/s/ MARK B. PUCKETT~~	~~Director~~	~~February 21, 2018~~
~~Mark B. Puckett~~

~~/s/ JOHN P. SURMA~~	~~Director~~	~~February 21, 2018~~
~~John P. Surma~~

~~/s/ E. JOSEPH WRIGHT~~	~~Director, Executive Vice President and Chief Operating Officer~~	~~February 21, 2018~~
~~E. Joseph Wright~~

Title of each class

Trading Symbol(s)

Name of each exchange

~~Title of each class~~

on which registered

Common Stock, $0.001 par value

New York Stock Exchange

~~The following terms are used throughout this report:~~

~~Bbl~~ ~~One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to oil, condensate or natural gas liquids.~~

~~Bcf~~ ~~One billion cubic feet of natural gas.~~

~~Boe~~ One barrel of oil equivalent, a standard convention used to express oil and natural gas volumes on a comparable oil equivalent basis. Natural gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of oil or condensate.

~~Basin~~ ~~A large natural depression on the earth’s surface in which sediments accumulate.~~

~~Development~~~~wells~~ ~~Wells drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.~~

~~Dry hole~~ ~~A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses, taxes and the royalty burden.~~

~~Exploratory wells~~ Wells drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

~~Field~~ An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

~~GAAP~~ ~~Generally accepted accounting principles in the United States of America.~~

~~Gross wells~~ ~~The number of wells in which a working interest is owned.~~

~~Horizontal drilling~~ A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a high angle to vertical (which can be greater than 90 degrees) in order to stay within a specified interval.

~~Infill drilling~~ ~~Drilling into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.~~

~~LIBOR~~ ~~London Interbank Offered Rate, which is a market rate of interest.~~

~~MBbl~~ ~~One thousand barrels of oil, condensate or natural gas liquids.~~

~~MBoe~~ ~~One thousand Boe.~~

~~Mcf~~ ~~One thousand cubic feet of natural gas.~~

~~MMBoe~~ ~~One million Boe.~~

~~MMBtu~~ ~~One million British thermal units.~~

~~MMcf~~ ~~One million cubic feet of natural gas.~~

~~NYMEX~~ ~~The New York Mercantile Exchange.~~

~~NYSE~~ ~~The New York Stock Exchange.~~

~~Net acres~~ ~~The percentage of total acres an owner owns out of a particular number of acres within a specified tract. For example, an owner who has a 50 percent interest in 100 acres owns 50 net acres.~~

~~Net wells~~ ~~The total of fractional working interests owned in gross wells.~~

~~PV-10~~ When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses except for specific general and administrative expenses incurred to operate the properties, discounted to a present value using an annual discount rate of 10 percent. PV-10 is a non-GAAP financial measure.

~~Productive wells~~ ~~Wells that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return.~~

~~Proved developed reserves~~ ~~Proved developed reserves are proved reserves that can be expected to be recovered:~~

~~(i)through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and~~

~~(ii)through installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well.~~

~~Supplemental definitions from the 2007 Petroleum Resources Management System:~~

Proved Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Proved Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but ~~which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells~~ not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, ~~production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.~~

~~Proved reserves~~ Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

~~(i)The area of the reservoir considered as proved includes:~~

~~(A)the area identified by drilling and limited by fluid contacts, if any, and~~

~~(B)~~adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

~~(A)~~successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

~~(B)the project has been approved for development by all necessary parties and entities, including governmental entities.~~

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

~~Proved undeveloped reserves~~ Proved undeveloped oil and natural gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

~~(i)~~Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

~~(ii)~~Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years from initial booking, unless the specific circumstances justify a longer time.

~~Recompletion~~ ~~The addition of production from another interval or formation in an existing wellbore.~~

~~Reservoir~~ ~~A formation beneath the surface of the earth from which hydrocarbons may be present. Its make-up is sufficiently homogenous to differentiate it from other formations.~~

~~Spacing~~ ~~The distance between wells producing from the same reservoir. Spacing is expressed in terms of acres, e.g., 40-acre spacing, and is established by regulatory agencies.~~

~~Standardized Measure~~ The present value (discounted at an annual rate of 10 percent) of estimated future net revenues to be generated from the production of proved reserves net of estimated income taxes associated with such net revenues, as determined in accordance with FASB guidelines, without giving effect to non-property related expenses such as indirect general and administrative expenses, and debt service or to depreciation, depletion and amortization. Standardized measure does not give effect to derivative transactions.

~~Undeveloped acreage~~ Acreage owned or leased on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

~~Wellbore~~ ~~The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called a well or borehole.~~

~~Working interest~~ The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

~~Workover~~ ~~Operations on a producing well to restore or increase production.~~

~~WTI~~ ~~West Texas Intermediate - light, sweet blend of oil produced from fields in western Texas.~~

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Financial Statements of Concho Resources Inc.:



Report of Independent Registered Public Accounting Firm	~~F-2~~ 62

Consolidated Balance Sheets at December 31, ~~2017~~2019 and ~~2016~~2018	~~F-3~~ 67

Consolidated Statements of Operations for the Years Ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~2017	~~F-4~~ 68

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~2017	~~F-5~~ 69

Consolidated Statements of Cash Flows for the Years Ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~2017	~~F-6~~ 70

Notes to Consolidated Financial Statements	~~F-7~~ 71

Unaudited Supplementary Data	~~F-44~~ 108

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Concho Resources Inc.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Concho Resources Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, ~~2017~~2019 and ~~2016,~~2018, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, ~~2017,~~2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2017~~2019 and ~~2016,~~2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2017,~~2019, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, ~~2017,~~2019, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February ~~21, 2018~~19, 2020 expressed an unqualified opinion.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Depletion and impairment of oil and natural gas properties

As described further in Note 2 to the financial statements, depletion and impairment of oil and natural gas properties involve judgments and estimates related to the Company’s oil and natural gas reserve quantities and associated future net cash flows. We identified depletion and impairment of oil and natural gas properties as a critical audit matter.

The principal considerations for our determination that depletion and impairment of oil and natural gas properties is a critical audit matter are due to the high risk of estimation uncertainty of the Company’s oil and natural gas reserve quantities and associated future net cash flows, which are key inputs within the Company’s depletion calculations and impairment analyses. The estimates of oil and natural gas reserve quantities and associated future net cash flows include management’s use of internal petroleum engineers and independent petroleum engineers and geologists (referred to as “management’s specialists”).

Our audit procedures related to depletion and impairment of oil and natural gas properties included the following, among others.

We tested the Company’s key inputs and assumptions used to estimate reserve quantities and future net cash flows, which include estimates of oil and natural gas prices, production costs, capital expenditures, division of interests, and the future estimated revenues based upon historical results and recent performance.

We obtained the Company’s oil and natural gas reserve reports prepared by management’s specialists and performed disaggregated analytical procedures to assess the reasonableness of the Company’s estimates.

We performed substantive testing on a sample of the data used by management’s specialists for reasonableness and accuracy.

We tested the Company’s depletion calculations and impairment analyses that included these oil and natural gas reserve quantities and future net cash flows.

We evaluated the level of knowledge, skill, and ability of management’s specialists and their relationship to the Company and made inquiries of management’s specialists regarding the process followed and judgments used to estimate the Company’s oil and natural gas reserves.

We tested the design and operating effectiveness of key controls related to oil and natural gas reserve estimates, depletion and impairment of oil and natural gas properties.

Nonmonetary transactions

As described further in Notes 2 and 5 to the financial statements, the Company completed multiple nonmonetary transactions, involving exchanges of both proved and unproved oil and natural gas properties. Certain of these transactions resulted in the Company recording the fair value of the assets and liabilities acquired and the recognition of non-cash gains and losses. We identified nonmonetary transactions as a critical audit matter.

The principal considerations for our determination that nonmonetary transactions is a critical audit matter are due to the high risk of estimation uncertainty of the fair value of proved and unproved oil and natural gas properties exchanged. These estimates of fair value are significantly based on the Company’s estimates of oil and natural gas reserve quantities and associated future net cash flows, which include management’s use of internal petroleum engineers (referred to as “management’s specialists”).

Our audit procedures related to nonmonetary transactions included the following, among others.

We obtained and inspected the contractual arrangements and the Company’s technical accounting documentation for the transactions tested.

We tested the Company’s key inputs and assumptions used to estimate reserve quantities and future net cash flows, which include estimates of oil and natural gas prices, production costs, division of interests, and the future estimated revenues based upon historical results and recent performance for properties received and divested.

We obtained the Company’s oil and natural gas reserves and performed disaggregated analytical procedures to assess the reasonableness of the Company’s estimates.

We performed substantive testing on a sample of the data used by management’s specialists for reasonableness and accuracy.

We tested the Company’s estimated fair value of unproved oil and natural gas properties exchanged based on available market data.

We utilized a valuation specialist to assist in the evaluation of these fair value estimates.

We tested the design and operating effectiveness of key controls related to nonmonetary transactions.

Goodwill impairment

As described further in Note 2 to the financial statements, goodwill is assessed for impairment on an annual basis, or more frequently if indicators of impairment exist. The balance of goodwill is allocated in its entirety to the Company’s one reporting unit. We identified goodwill impairment as a critical audit matter.

The principal considerations for our determination that goodwill impairment is a critical audit matter are due to the high risk of estimation uncertainty related to the estimated fair value of the business operations with which goodwill is associated. The fair value estimate is based on the Company’s enterprise value calculated as the combined market capitalization of the Company’s equity, which includes a control premium, plus the fair value of the Company’s long-term debt. Changes in the estimates and judgments could have a significant impact on the fair value of the Company and the resulting amount of any goodwill impairment. Auditing management’s estimates and judgments regarding the Company’s stock prices, control premiums used, and the fair value of long-term debt involved a high degree of auditor subjectivity and required an increased extent of effort when performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions, including the need to involve a valuation specialist.

Our audit procedures related to goodwill impairment included the following, among others.

We obtained and tested the Company’s key inputs and assumptions used to estimate the Company’s enterprise value.

We obtained market evidence to evaluate the estimated fair value of the Company’s equity, including historical stock price information and control premiums of recent stock transactions.

We obtained market evidence to evaluate the estimated fair value of the Company’s long-term debt.

We utilized a valuation specialist to assist in the evaluation of these fair value estimates.

We tested the design and operating effectiveness of key controls related to goodwill impairment.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2004.

Oklahoma City, Oklahoma

February ~~21, 2018~~

19, 2020

F-2

GLOSSARY OF TERMS



The following terms are used throughout this report:
Bbl	One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to oil, condensate or natural gas liquids.

Bcf	One billion cubic feet of natural gas.

Boe	One barrel of oil equivalent, a standard convention used to express oil and natural gas volumes on a comparable oil equivalent basis. Natural gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of oil or condensate.

Basin	A large natural depression on the earth’s surface in which sediments accumulate.

Brent	Brent oil price, a major trading classification of sweet light oil that serves as a benchmark price for purchases of oil worldwide.

Developmentwells	Wells drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole	A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses, taxes and the royalty burden.

Exploratory wells	Wells drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

Field	An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

GAAP	Generally Accepted Accounting Principles in the United States of America.

Gross wells	The number of wells in which a working interest is owned.

Horizontal drilling	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a high angle to vertical (which can be greater than 90 degrees) in order to stay within a specified interval.

Infill drilling	Drilling into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

LIBOR	London Interbank Offered Rate, which is a market rate of interest.

MBbl	One thousand barrels of oil, condensate or natural gas liquids.

MBoe	One thousand Boe.

Mcf	One thousand cubic feet of natural gas.

MMBoe	One million Boe.

MMBtu	One million British thermal units.

MMcf	One million cubic feet of natural gas.

NYMEX	The New York Mercantile Exchange.

NYSE	The New York Stock Exchange.

Net acres	The percentage of total acres an owner owns out of a particular number of acres within a specified tract. For example, an owner who has a 50 percent interest in 100 acres owns 50 net acres.

Net wells	The total of fractional working interests owned in gross wells.

PV-10	When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses except for specific general and administrative expenses incurred to operate the properties, discounted to a present value using an annual discount rate of 10 percent. PV-10 is a non-GAAP financial measure.

Productive wells	Wells that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return.

Proved developed reserves	Proved developed reserves are proved reserves that can be expected to be recovered:




	(i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

	(ii) through installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well.

	Supplemental definitions from the 2007 Petroleum Resources Management System:

	Proved Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

	Proved Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Proved reserves	Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

	(i) The area of the reservoir considered as proved includes:

	(A) the area identified by drilling and limited by fluid contacts, if any, and

	(B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data.

	(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

	(iii) Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

	(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

	A) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

	(B) the project has been approved for development by all necessary parties and entities, including governmental entities.

	(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves	Proved undeveloped oil and natural gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.



	(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

	(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years from initial booking, unless the specific circumstances justify a longer time.

Recompletion	The addition of production from another interval or formation in an existing wellbore.

Reservoir	A formation beneath the surface of the earth from which hydrocarbons may be present. Its make-up is sufficiently homogenous to differentiate it from other formations.

Spacing	The distance between wells producing from the same reservoir. Spacing is expressed in terms of acres, e.g., 40-acre spacing, and is established by regulatory agencies.

Standardized Measure	The present value (discounted at an annual rate of 10 percent) of estimated future net revenues to be generated from the production of proved reserves net of estimated income taxes associated with such net revenues, as determined in accordance with FASB guidelines, without giving effect to non-property related expenses such as indirect general and administrative expenses, and debt service or to depreciation, depletion and amortization. Standardized measure does not give effect to derivative transactions.

Undeveloped acreage	Acreage owned or leased on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore	The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called a well or borehole.

Working interest	The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

Workover	Operations on a producing well to restore or increase production.

WTI	West Texas Intermediate - light, sweet blend of oil produced from fields in western Texas.

Concho Resources Inc.

Consolidated Balance Sheets

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

331

220

Joint operations and other

212

238

Inventory

14

16

Derivative instruments

-

4

Prepaid costs and other

35

31


Total current assets

592

562
Property and equipment:

Oil and natural gas properties, successful efforts method

21,267

18,476

Accumulated depletion and depreciation

(8,460)

(7,390)

Total oil and natural gas properties, net

12,807

11,086

Other property and equipment, net

234

216

Total property and equipment, net

13,041

11,302
Funds held in escrow

-

43
Deferred loan costs, net

13

11
Intangible assets, net

26

24
Other assets

60

177

Total assets

$
13,732

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

Accounts payable - trade

$
43

$
28

Bank overdrafts

116

-

Revenue payable

183

132

Accrued drilling costs

330

359

Derivative instruments

277

82

Other current liabilities

216

152


Total current liabilities

1,165

753
Long-term debt

2,691

2,741
Deferred income taxes

687

766
Noncurrent derivative instruments

102

96
Asset retirement obligations and other long-term liabilities

172

140
Commitments and contingencies (Note 10)

Stockholders’ equity:

Common stock, $0.001 par value; 300,000,000 authorized; 149,324,849 and 146,488,685

shares issued at December 31, 2017 and 2016, respectively

-

-

Additional paid-in capital

7,142

6,783

Retained earnings

1,840

884

Treasury stock, at cost; 598,049 and 429,708 shares at December 31, 2017 and 2016,

respectively

(67)

(44)


Total stockholders’ equity

8,915

7,623

Total liabilities and stockholders’ equity

$
13,732

$
12,119

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

F-3



	December 31,
(in millions, except share and per share amounts)	2019			2018
Assets
Current assets:
Cash and cash equivalents	$	70		$	—
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas	584			466
Joint operations and other	304			365
Inventory	30			35
Derivative instruments	6			484
Prepaid costs and other	61			59
Total current assets	1,055			1,409
Property and equipment:
Oil and natural gas properties, successful efforts method	28,785			31,706
Accumulated depletion and depreciation	(7,895		)	(9,701		)
Total oil and natural gas properties, net	20,890			22,005
Other property and equipment, net	437			308
Total property and equipment, net	21,327			22,313
Deferred loan costs, net	7			10
Goodwill	1,917			2,224
Intangible assets, net	17			19
Noncurrent derivative instruments	11			211
Other assets	398			108
Total assets	$	24,732		$	26,294
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable - trade	$	53		$	50
Book overdrafts	—			159
Revenue payable	268			253
Accrued drilling costs	386			574
Derivative instruments	112			—
Other current liabilities	363			320
Total current liabilities	1,182			1,356
Long-term debt	3,955			4,194
Deferred income taxes	1,654			1,808
Noncurrent derivative instruments	7			—
Asset retirement obligations and other long-term liabilities	152			168
Commitments and contingencies (Note 11)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 198,863,681 and 201,288,884 shares issued at December 31, 2019 and 2018, respectively	—			—
Additional paid-in capital	14,608			14,773
Retained earnings	3,320			4,126
Treasury stock, at cost; 1,175,026 and 1,031,655 shares at December 31, 2019 and 2018, respectively	(146		)	(131		)
Total stockholders’ equity	17,782			18,768
Total liabilities and stockholders’ equity	$	24,732		$	26,294

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

Concho Resources Inc.

Consolidated Statements of Operations

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

2017

2016

2015

Operating revenues:

Oil sales

$
2,092

$
1,350

$
1,540

Natural gas sales

494

285

264

Total operating revenues

2,586

1,635

1,804
Operating costs and expenses:

Oil and natural gas production

408

320

390

Production and ad valorem taxes

199

131

151

Exploration and abandonments

59

77

59

Depreciation, depletion and amortization

1,146

1,167

1,223

Accretion of discount on asset retirement obligations

8

7

8

Impairments of long-lived assets

-

1,525

61

General and administrative (including non-cash stock-based compensation of $60,

$59 and $63 for the years ended December 31, 2017, 2016 and 2015, respectively)

244

226

231

(Gain) loss on derivatives

126

369

(700)

(Gain) loss on disposition of assets, net

(678)

(118)

54

Total operating costs and expenses

1,512

3,704

1,477
Income (loss) from operations

1,074

(2,069)

327
Other income (expense):

Interest expense

(146)

(204)

(215)

Loss on extinguishment of debt

(66)

(56)

-

Other, net

19

(9)

(15)

Total other expense

(193)

(269)

(230)
Income (loss) before income taxes

881

(2,338)

97

Income tax (expense) benefit

75

876

(31)
Net income (loss)

$
956

$
(1,462)

$
66
Earnings per share:

Basic net income (loss)

$
6.44

$
(10.85)

$
0.54

Diluted net income (loss)

$
6.41

$
(10.85)

$
0.54

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

F-4



	Years Ended December 31,
(in millions, except per share amounts)	2019			2018			2017
Operating revenues:
Oil sales	$	4,126		$	3,443		$	2,092
Natural gas sales	466			708			494
Total operating revenues	4,592			4,151			2,586
Operating costs and expenses:
Oil and natural gas production	716			590			408
Production and ad valorem taxes	349			305			199
Gathering, processing and transportation	115			55			—
Exploration and abandonments	201			65			59
Depreciation, depletion and amortization	1,964			1,478			1,146
Accretion of discount on asset retirement obligations	10			10			8
Impairments of long-lived assets	890			—			—
Impairments of goodwill	282			—			—
General and administrative (including non-cash stock-based compensation of $85, $82 and $60 for the years ended December 31, 2019, 2018 and 2017, respectively)	326			311			244
(Gain) loss on derivatives	895			(832		)	126
Gain on disposition of assets, net	(170		)	(800		)	(678		)
Transaction costs	1			39			3
Total operating costs and expenses	5,579			1,221			1,515
Income (loss) from operations	(987		)	2,930			1,071
Other income (expense):
Interest expense	(185		)	(149		)	(146		)
Loss on extinguishment of debt	—			—			(66		)
Other, net	313			108			22
Total other income (expense)	128			(41		)	(190		)
Income (loss) before income taxes	(859		)	2,889			881
Income tax (expense) benefit	154			(603		)	75
Net income (loss)	$	(705	)	$	2,286		$	956
Earnings per share:
Basic net income (loss)	$	(3.55	)	$	13.28		$	6.44
Diluted net income (loss)	$	(3.55	)	$	13.25		$	6.41

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

Concho Resources Inc.

Consolidated Statements of Stockholders’ Equity

Common Stock Issued
Additional

Total

Paid-in
Retained

Treasury Stock
Stockholders’
(in millions, except share data)

Shares

Amount
Capital
Earnings

Shares

Amount
Equity

(in thousands)

(in thousands)

BALANCE AT JANUARY 1, 2015

113,265

$
-

$
3,028

$
2,280

260

$
(27)

$
5,281

Net income

-

-

-

66

-

-

66

Issuance of common stock

15,755

-

1,536

-

-

-

1,536

Stock options exercised

5

-

-

-

-

-

-

Grants of restricted stock

452

-

-

-

-

-

-

Cancellation of restricted stock

(33)

-

-

-

-

-

-

Stock-based compensation

-

-

63

-

-

-

63

Excess tax benefits related to stock-based

compensation

-

-

2

-

-

-

2

Purchase of treasury stock

-

-

-

-

46

(5)

(5)
BALANCE AT DECEMBER 31, 2015

129,444

-

4,629

2,346

306

(32)

6,943

Net loss

-

-

-

(1,462)

-

-

(1,462)

Issuance of common stock

10,350

-

1,327

-

-

-

1,327

Common stock issued in business combinations

6,134

-

768

-

-

-

768

Stock options exercised

23

-

1

-

-

-

1

Grants of restricted stock

451

-

-

-

-

-

-

Performance unit share conversion

180

-

-

-

-

-

-

Cancellation of restricted stock

(93)

-

-

-

-

-

-

Stock-based compensation

-

-

59

-

-

-

59

Tax deficiency related to stock-based

��

compensation

-

-

(1)

-

-

-

(1)

Purchase of treasury stock

-

-

-

-

124

(12)

(12)
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

-

-

-

956

-

-

956

Common stock issued in business combinations

2,177

-

291

-

-

-

291

Stock options exercised

20

-

-

-

-

-

-

Grants of restricted stock

490

-

-

-

-

-

-

Performance unit share conversion

249

-

-

-

-

-

-

Cancellation of restricted stock

(100)

-

-

-

-

-

-

Stock-based compensation

-

-

60

-

-

-

60

Purchase of treasury stock

-

-

-

-

168

(23)

(23)
BALANCE AT DECEMBER 31, 2017

149,325

$
-

$
7,142

$
1,840

598

$
(67)

$
8,915

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

F-5



	Common Stock Issued				Additional Paid-in Capital			Retained Earnings			Treasury Stock				Total Stockholders’ Equity
(in millions, except share data)	Shares		Amount		Additional Paid-in Capital			Retained Earnings			Shares	Amount			Total Stockholders’ Equity
	(in thousands)										(in thousands)
BALANCE AT JANUARY 1, 2017	146,489		$	—	$	6,791		$	884		430	$	(44	)	$	7,631
Net income	—		—		—			956			—	—			956
Common stock issued in business combinations	2,177		—		291			—			—	—			291
Stock options exercised	20		—		—			—			—	—			—
Grants of restricted stock	490		—		—			—			—	—			—
Performance unit share conversion	249		—		—			—			—	—			—
Cancellation of restricted stock	(100	)	—		—			—			—	—			—
Stock-based compensation	—		—		60			—			—	—			60
Purchase of treasury stock	—		—		—			—			168	(23		)	(23		)
BALANCE AT DECEMBER 31, 2017	149,325		—		7,142			1,840			598	(67		)	8,915
Net income	—		—		—			2,286			—	—			2,286
Common stock issued in business combinations	50,915		—		7,549			—			—	—			7,549
Grants of restricted stock	687		—		—			—			—	—			—
Performance unit share conversion	447		—		—			—			—	—			—
Cancellation of restricted stock	(85	)	—		—			—			—	—			—
Stock-based compensation	—		—		82			—			—	—			82
Purchase of treasury stock	—		—		—			—			434	(64		)	(64		)
BALANCE AT DECEMBER 31, 2018	201,289		—		14,773			4,126			1,032	(131		)	18,768
Net loss	—		—		—			(705		)	—	—			(705		)
Common stock repurchased and retired	(3,300	)	—		(250		)	—			—	—			(250		)
Grants of restricted stock	776		—		—			—			—	—			—
Performance unit share conversion	246		—		—			—			—	—			—
Cancellation of restricted stock	(147	)	—		—			—			—	—			—
Stock-based compensation	—		—		85			—			—	—			85
Common stock dividends ($0.50 per share)	—		—		—			(101		)	—	—			(101		)
Purchase of treasury stock	—		—		—			—			143	(15		)	(15		)
BALANCE AT DECEMBER 31, 2019	198,864		$	—	$	14,608		$	3,320		1,175	$	(146	)	$	17,782

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

Concho Resources Inc.

Consolidated Statements of Cash Flows

Years Ended December 31,
(in millions)

2017

2016

2015
CASH FLOWS FROM OPERATING ACTIVITIES:

Net income (loss)

$
956

$
(1,462)

$
66

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

Depreciation, depletion and amortization

1,146

1,167

1,223

Accretion of discount on asset retirement obligations

8

7

8

Impairments of long-lived assets

-

1,525

61

Exploration and abandonments, including dry holes

27

57

34

Non-cash stock-based compensation expense

60

59

63

Deferred income taxes

(71)

(864)

30

(Gain) loss on disposition of assets, net

(678)

(118)

54

(Gain) loss on derivatives

126

369

(700)

Net settlements received from derivatives

79

625

633

Loss on extinguishment of debt

66

56

-

Other non-cash items

(1)

14

14

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

Accounts receivable

(126)

32

128

Prepaid costs and other

(9)

6

(4)

Inventory

-

2

(5)

Accounts payable

14

15

(18)

Revenue payable

52

(38)

(68)

Other current liabilities

46

(68)

11

Net cash provided by operating activities

1,695

1,384

1,530
CASH FLOWS FROM INVESTING ACTIVITIES:

Additions to oil and natural gas properties

(1,581)

(1,046)

(2,185)

Acquisitions of oil and natural gas properties

(908)

(1,351)

(259)

Additions to property, equipment and other assets

(44)

(61)

(67)

Proceeds from the disposition of assets

803

332

-

Deposits on dispositions of oil and natural gas properties

29

-

-

Direct transaction costs for disposition of assets

(18)

-

-

Funds held in escrow

-

(43)

-

Contributions to equity method investments

-

(56)

(91)



Net cash used in investing activities

(1,719)

(2,225)

(2,602)
CASH FLOWS FROM FINANCING ACTIVITIES:

Proceeds from issuance of debt

2,795

600

1,491

Payments of debt

(2,829)

(1,200)

(1,630)

Debt extinguishment costs

(63)

(42)

-

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

-

(1)

2

Net proceeds from issuance of common stock

-

1,327

1,536

Payments for loan costs

(25)

(7)

-

Purchase of treasury stock

(23)

(12)

(5)

Increase (decrease) in bank overdrafts

116

-

(93)



Net cash provided by (used in) financing activities

(29)

665

1,301



Net increase (decrease) in cash and cash equivalents

(53)

(176)

229
Cash and cash equivalents at beginning of period

53

229

-
Cash and cash equivalents at end of period

$
-

$
53

$
229
SUPPLEMENTAL CASH FLOWS:

Cash paid for interest

$
139

$
232

$
211

Cash paid for income taxes

$
13

$
-

$
4
NON-CASH INVESTING AND FINANCING ACTIVITIES:

Issuance of common stock for business combinations

$
291

$
768

$
-

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

F-6



	Years Ended December 31,
(in millions)	2019			2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(705	)	$	2,286		$	956
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	1,964			1,478			1,146
Accretion of discount on asset retirement obligations	10			10			8
Impairments of long-lived assets	890			—			—
Impairments of goodwill	282			—			—
Exploration and abandonments	166			35			27
Non-cash stock-based compensation expense	85			82			60
Deferred income taxes	(154		)	605			(71		)
Net gain on disposition of assets and other non-operating items	(459		)	(800		)	(678		)
(Gain) loss on derivatives	895			(832		)	126
Net settlements received from (paid on) derivatives	(98		)	(218		)	79
Loss on extinguishment of debt	—			—			66
Other	—			(92		)	(1		)
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable	(90		)	(35		)	(126		)
Prepaid costs and other	(2		)	(10		)	(9		)
Inventory	1			(12		)	—
Accounts payable	3			1			14
Revenue payable	28			52			52
Other current liabilities	20			8			46
Net cash provided by operating activities	2,836			2,558			1,695
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and natural gas properties	(3,069		)	(2,496		)	(1,581		)
Acquisitions of oil and natural gas properties	(54		)	(136		)	(908		)
Additions to property, equipment and other assets	(117		)	(90		)	(44		)
Proceeds from the disposition of assets	1,260			361			832
Direct transaction costs for asset acquisitions and dispositions	(13		)	(3		)	(18		)
Distribution from equity method investment	—			148			—
Net cash used in investing activities	(1,993		)	(2,216		)	(1,719		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	2,935			3,316			1,001
Payments on credit facility	(3,177		)	(3,396		)	(679		)
Issuance of senior notes, net	—			1,595			1,794
Repayments of senior notes	—			—			(2,150		)
Repayments of RSP debt	—			(1,690		)	—
Debt extinguishment costs	—			(83		)	(63		)
Payments for loan costs	—			(16		)	(25		)
Payment of common stock dividends	(100		)	—			—
Purchases of treasury stock	(15		)	(64		)	(23		)
Purchases of common stock under share repurchase program	(250		)	—			—
Increase (decrease) in book overdrafts	(159		)	(4		)	116
Other	(7		)	—			—
Net cash used in financing activities	(773		)	(342		)	(29		)
Net increase (decrease) in cash and cash equivalents	70			—			(53		)
Cash and cash equivalents at beginning of period	—			—			53
Cash and cash equivalents at end of period	$	70		$	—		$	—
SUPPLEMENTAL CASH FLOWS:
Cash paid for interest	$	207		$	118		$	139
Cash paid for income taxes	$	—		$	2		$	13
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Issuance of common stock for business combinations	$	—		$	7,549		$	291

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

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

Note 1. Organization and nature of operations

Concho Resources Inc., a Delaware corporation (the “Company”) is ~~a Delaware corporation formed on February 22, 2006. The Company’s principal business 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 of significant accounting policies

Principles of consolidation.The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The consolidated financial statements also ~~include~~included the accounts of a variable interest entity (“VIE”) where the Company was the primary beneficiary of the arrangements ~~during~~until the ~~year ended December 31, 2017.~~VIE structure dissolved in January 2018. See Note 45 for additional information regarding the circumstances surrounding the VIE. The Company consolidates the financial statements of these entities. All material intercompany balances and transactions have been eliminated.

Reclassifications. Certain prior period amounts have been reclassified to conform to the ~~2017~~2019 presentation. These reclassifications had no impact on net income (loss), total assets, liabilities and stockholders’ equity or total cash flows.

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

Assets held for sale. On the date at which the Company determines the asset group met all of the held for sale criteria, the Company discontinues the recording of depletion and depreciation of the asset or asset group to be sold and reclassifies these assets as held for sale in its consolidated balance sheets. The assets held for sale are measured at the fair value less cost to sell.

Cash and cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are generally held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. At December 31, ~~2016,~~2019, the majority of the Company’s cash was invested in stable value government money market funds.

Accounts receivable. The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Oil and natural gas sales receivables related to these operations are generally unsecured. Joint interest receivables are generally secured pursuant to the operating agreement between or among the co-owners of the operated property. The Company determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and the Company’s ability to realize the receivables through netting of anticipated future production revenues. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The Company had an allowance for doubtful accounts of ~~approximately $1~~$7 million and $5 million for ~~each of~~ the years ended December 31, ~~2017~~2019 and ~~2016.~~

2018, respectively.

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

value.

Oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized leasehold costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized drilling and development costs and integrated assets is based on the unit-of-production method using proved developed reserves. ~~During~~The Company recognized depletion expense of approximately $1.9 billion, $1.5 billion and $1.1 billion during the years ended December 31, 2019, 2018 and 2017, ~~2016 and 2015, the Company recognized depletion expense from operations of $1,122 million, $1,145 million and $1,203 million,~~ respectively.

F-7

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

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

~~(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.~~


(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.

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

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

Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed. The Company capitalizes interest ~~if debt is outstanding,~~ on expenditures for significant development projects until such projects are ready for their intended use. During the years ended December 31, ~~2017~~2019 and ~~2015,~~2018, the Company ~~had~~ capitalized interest of ~~approximately $3~~$19 million and $1$8 million, ~~respectively. The Company did not have capitalized interest~~respectively, primarily related to ~~significant oil and natural gas~~the Company’s development ~~projects for the year ended December 31, 2016.~~

projects.

The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be ~~recoverable.~~recoverable, for instance when there are declines in commodity prices or well performance. The Company reviews its oil and natural gas properties by depletion base. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by depletion base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties and integrated assets would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs and cash flows from integrated assets. The Company recognized an impairment expense of ~~approximately $1.5 billion and $61~~$890 million during the ~~years~~year ended December 31, ~~2016 and 2015, respectively,~~2019 related to its proved oil and natural gas ~~properties. The Company~~properties, but did not recognize an impairment expense during the ~~year~~years ended December 31, 2018 and 2017. See Note 78 for additional information regarding the Company’s impairment expense.

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects. During the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015,~~2017, the Company recognized expense of ~~approximately $~~29 $147 million, $60 $35 million and $35 $27 million, respectively, related to abandoned and expiring acreage, which is included in exploration and abandonments expensein the accompanying consolidated statements of operations.

Other property and equipment. Other capital assets include buildings, transportation equipment, computer equipment and software, telecommunications equipment, leasehold improvements and furniture and fixtures. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two years to 39 years. The Company had other capital assets of ~~$234~~$437 million and ~~$216~~$308 million, net of accumulated depreciation of ~~$90~~$126 million and ~~$74~~$109 million, at December 31, ~~2017~~2019 and December 31, ~~2016,~~2018, respectively. During the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015,~~2017, the Company recognized depreciation expense of $30 million, $22 million and $21 million, ~~$21 million~~respectively.

Nonmonetary transactions. In connection with nonmonetary transactions, which include exchanges of producing and ~~$19 million, respectively. During the year ended December 31, 2015,~~non-producing assets, the Company ~~had capitalized interest~~must evaluate the transaction to determine appropriate accounting treatment. In general, the basic principle of ~~approximately $1 million.~~accounting for nonmonetary transactions is based on the fair values involved, which is the same basis used in monetary transactions and results in the recognition of gains and losses. However, certain nonmonetary transactions meet criteria that require modification of the basic principle that necessitate recording values based on historical book value. The Company ~~did not have capitalized interest related to other property~~determines the treatment of nonmonetary transactions based on the individual facts and ~~equipment~~

circumstances of each transaction. In cases where nonmonetary transactions are recorded at fair value, the Company makes various assumptions. The most significant assumptions

F-8

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Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

~~during the years ended December 31, 2017 or 2016.~~

~~Funds held in escrow.~~ At December 31, 2016, the Company’s funds held in escrow totaled $43 million, which consisted of a deposit paid by the Company that was held in escrow for its Northern Delaware Basin acquisition. See Note 4 for additional information regarding the acquisition.

~~Deferred loan costs.~~ ~~Deferred loan costs~~

are ~~stated at cost, net of amortization, which is computed using the straight-line method. The Company had deferred loan costs~~ related to ~~its credit facility of $~~13 ~~million and $~~11 ~~million, net of accumulated amortization of $51million and $~~56 ~~million, in noncurrent assets at December 31, 2017 and 2016, respectively.~~

~~Intangible assets.~~ ~~The Company has capitalized certain rights acquired through acquisitions. The gross intangible assets, which have no residual value, are amortized over~~ the estimated ~~economic life~~fair values assigned to proved and unproved oil and natural gas properties, similar to the valuation of ~~three to 25 years. Impairment will be~~the fair value of oil and natural gas assets acquired during a business combination. Any resulting difference between the fair value of the assets involved and their carrying value is recorded as a gain or loss in the consolidated statement of operations.

Goodwill. Goodwill is assessed for impairment on an annual basis, or more frequently if indicators of ~~potential~~ impairment ~~exist or when there~~exist. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed as of July 1 of each year. The balance of goodwill is allocated in its entirety to the Company’s one reporting unit. 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 ~~material change~~control premium, and 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 annual quantitative impairment test during the third quarter of 2019. The fair value of the reporting unit exceeded the carrying value of net assets at July 1, 2019.

As discussed in Note 5, in August 2019, the Company entered into a definitive agreement to sell its assets in the ~~remaining useful economic life.~~ ~~The following table reflects the gross and net intangible assets at December 31, 2017 and 2016, respectively:~~

December 31,
(in millions)

2017

2016

Gross intangibles

$
42

$
37
Accumulated amortization


(16)

(13)

Net intangibles

$
26

$
24

New Mexico Shelf. The Company ~~recognized amortization expense~~classified these assets as held for sale at August 29, 2019. The Company allocated $81 million of ~~approximately $3 million~~goodwill to this disposal group, all of which the Company impaired. This impairment charge was recorded in impairments of goodwill on the consolidated statements of operations for the year ended December 31, ~~2017~~2019. See Note 8 for additional impairment discussion of this disposal group. In conjunction with the allocation and ~~approximately $1~~impairment of goodwill related to the New Mexico Shelf disposal group, the Company performed a quantitative impairment test for the remaining goodwill. No additional impairment was recorded as the fair value of the reporting unit exceeded the carrying value.

The Company also performed an impairment test at September 30, 2019 due to declines in the Company’s market capitalization and at December 31, 2019 due to declines in observed control premiums. The estimated fair value of the reporting unit at September 30, 2019 exceeded the carrying value of our net assets. However, during the fourth quarter of 2019, the Company’s estimated fair value declined further resulting in a $201 million impairment charge at December 31, 2019. As such, the Company recorded total impairment charges of $282 million during the year ended December 31, 2019. The Company used an average stock price over a determined period to estimate the fair value of the reporting unit at December 31, 2019, which the Company believes removes the impact of short term market fluctuations. In addition, the Company’s control premium was based on the estimated median control premium of transactions involving companies in the Company’s industry. The Company did not recognize an impairment expense during the year ended December 31, 2018.

It is reasonably possible that the estimates of our enterprise value may change in the future resulting in the need to impair goodwill. Currently, the primary factor that may negatively affect the Company’s enterprise value is a continued depressed level of the Company’s stock price. Many factors affecting the Company’s stock price are beyond the Company’s control and the Company cannot predict the potential effects on the price of its common stock. Stock markets in general can also experience considerable price and volume fluctuations. In addition, deteriorating industry, market and economic conditions could negatively impact the control premium and the Company’s enterprise value, which could lead to additional impairments of the Company’s goodwill balance.

Equity method investments. The Company holds membership interests in certain entities and accounts for ~~each~~these investments using the equity method of accounting.

The Company owns a 50 percent membership interest in Beta Holding Company, LLC, a midstream joint venture formed to construct a crude oil gathering system in the Midland Basin.

The Company owns a 20 percent membership interest in Solaris Midstream Holdings, LLC, an entity that owns and operates water gathering, transportation, disposal, recycling and storage infrastructure assets in the Permian Basin.

The Company 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 equity method investment balance in other assets on the consolidated balance sheets. The Company records its share of equity investment earnings and losses in other income (expense) on the consolidated statements of operations. Equity investment earnings and losses are adjusted to account for any basis difference. The Company recorded equity method investment income of $12 million, $4 million and $7 million for the years ended December 31, ~~2016~~2019, 2018 and ~~2015.~~2017, respectively. The Company ~~will record amortization expense~~also contributed certain water infrastructure assets and recorded a gain of ~~approximately $3~~$297 million and $79 million, which is included in gain on disposition of assets, net on the Company’s consolidated statements of operations for the years ended December 31, 2019 and 2018, respectively.

Until May 2019, the Company owned a 23.75 percent membership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that owned and operated Oryx I, a crude oil gathering and transportation system in the Delaware Basin (“Oryx I”). In February 2018, Oryx obtained a term loan of $800 million. The proceeds were used in part to fund a cash distribution to its equity holders, of which the Company received a distribution of $157 million. Of this amount, $54 million fully offset the Company’s net

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Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

investment in Oryx. The net investment of $54 million included $45 million of the Company’s contributions made to Oryx and $9 million of equity income. The remaining distribution of $103 million was recorded in other income (expense) on the Company’s consolidated statement of operations for the year ended December 31, ~~2018~~2018. In May 2019, Oryx completed the sale of 100 percent of its equity interests in Oryx I. The Company received $289 million, net of closing costs, in connection with the sale of Oryx I and ~~approximately $1 million for each of the remaining years under the term.~~

~~Equity method investments.~~ ~~Equity method investments are included in other assets in the Company’s consolidated balance sheets. Income and losses incurred from the Company’s equity investments are~~ recorded a gain in other income (expense) ~~in its~~on the Company’s consolidated ~~statements~~statement of ~~operations.~~

Atoperations for the year ended December 31, ~~2016,~~2019.

In February 2017, the Company ~~owned a~~closed on the divestiture of its 50 percent membership interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), that constructed a crude oil gathering and transportation system in the ~~Northern~~ Delaware Basin. The Company’s net investment in ACC was approximately $129 million at December 31, 2016. During the years ended December 31, 2016 and 2015, the Company recorded a loss of approximately $2 million and $4 million, respectively. In February 2017, the Company closed on the divestiture of its ownership interest in ACC. See Note 45 for additional information regarding the disposition of ACC.

~~The Company owns a membership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering~~

Regulatory and transportation system in the Southern Delaware Basin. During 2017, the Company’s membership interest was reduced from 25 percent to 23.75 percent after the addition of a new partner. The Company’s net investment was approximately $49 million and $42 million at December 31, 2017 and 2016, respectively. During the years ended December 31, 2017 and 2016, the Company recorded income of approximately $7 million and a loss of approximately $2 million, respectively.

~~Environmental.~~environmental compliance. The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Regulatory liabilities relate to acquisitions where additional equipment is necessary to have facilities compliant with local, state and federal obligations and are capitalized. Environmental expenditures ~~are expensed. Expenditures~~ that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures ~~of a~~that are noncapital in nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. ~~At December 31, 2017~~Environmental liabilities normally involve estimates that are subject to revisions until settlement occurs. See Note 11 for additional information.

Litigation contingencies. The Company is a party to proceedings and ~~2016,~~claims incidental to its business. In each reporting period, the Company ~~has accrued approximately $~~3 ~~million~~assesses these claims in an effort to determine the degree of probability and $1 ~~million, respectively, related to environmental liabilities. During~~range of possible loss for potential accrual in its consolidated financial statements. The amount of any resulting losses may differ from these estimates. An accrual is recorded for a material loss contingency when its occurrence is probable and the ~~years ended December 31, 2017, 2016 and 2015, the Company recognized environmental charges of approximately $~~9 ~~million, $~~7 ~~million and $~~3 ~~million, respectively.~~

~~Senior note deferred loan costs.~~~~Senior note deferred loan costs are stated at cost, net of amortization, which~~amount is ~~computed using the effective interest method. The Company had senior note deferred loan costs of $25 million and $31~~

F-9

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

~~million, net of accumulated amortization of $1 million and $12 million, as a reduction of long-term debt at December 31, 2017 and 2016, respectively.~~reasonably estimable. See Note 911 for additional ~~information regarding activity related to the Company’s senior notes.~~

information.

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

The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. At December 31, 2019 and 2018, the Company had unrecognized tax benefits primarily related to research and development credits. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company’s deferred tax liability and will affect the Company’s effective tax rate in the period recognized. The timing as to when the Company will substantially resolve the uncertainties associated with the unrecognized tax benefit is uncertain. The Company ~~had no material uncertain~~has not recognized any interest or penalties relating to unrecognized tax ~~positions that required recognition~~benefits in ~~the~~its consolidated financial ~~statements at December 31, 2017 or 2016.~~statements. Any interest or penalties would be recognized as a component of income tax expense.

On December 22, 2017, the President of the United States ~~(“the President”~~(the “President”) signed into law the tax bill commonly referred to as the “Tax Cuts and Job Act” (“TCJA”), significantly changing federal income tax laws. According to the Accounting Standards Codification (“ASC”) section 740, “Income Taxes,” (“ASC 740”), a company is required to record the effects of an enacted tax law or rate change in the period of enactment, which is the date the bill is signed by the President and becomes law. As a result of the enactment of the TCJA, the U.S. Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” (“SAB 118”)to provide guidance for companies that have not completed the accounting for the income tax effects of the TCJA in the period of enactment. SAB 118 ~~allows~~allowed companies to report provisional amounts when based on reasonable estimates and to adjust these amounts during a measurement period of up to one year. The Company ~~has~~ elected to apply SAB 118 and, as such, ~~has~~ recorded provisional amounts for the income tax balances reported in its consolidated financial ~~statements. The~~statements at December 31, 2017. At December 31, 2018, the Company ~~will continue to monitor any new administrative guidance or tax law interpretation. See Note 11 for additional information regarding the Company’s deferred tax balances and~~completed its accounting for ~~the impacts~~all tax effects of the ~~TCJA.~~

TCJA and made an adjustment to its provisional amounts related to the deductibility of certain compensation based on available regulatory and interpretive guidance.

Derivative instruments. The Company recognizes its derivative instruments, other than ~~any~~ commodity derivative contracts that are designated as normal purchase and normal sale contracts, as either assets or liabilities measured at fair value. The Company ~~netted~~

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Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

nets the fair value of the derivative instruments by counterparty in the accompanying consolidated balance sheets ~~where~~when the right of offset exists. The Company does not have any derivatives designated as fair value or cash flow hedges. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated ~~financial statements.~~

balance sheets.

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

~~Treasury~~

Purchases of common stock. ~~Treasury~~ Common stock ~~purchases are~~purchased and held in treasury is recorded at cost.

For common stock repurchased and retired, the excess of cost over par value is charged to additional paid-in capital.

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

The Company recognizes revenues from the sales of oil and natural gas to its customers and presents them disaggregated on the Company’s consolidated statements of operations. All revenues are recognized in the geographical region of the Permian Basin. Prior to the adoption of ASC 606, the Company recorded oil and natural gas revenues ~~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~~followed the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.

~~Oil~~

The Company enters into contracts with customers to sell its oil and natural gas ~~imbalances.~~~~Oil~~production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas ~~imbalances~~to the purchaser. Control is generally considered transferred when the following criteria are ~~generated~~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 ~~properties~~the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. At December 31, 2019 and 2018, the Company had receivables related to contracts with customers of $584 million and $466 million, respectively.

Oil Contracts. The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing which is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred after the transfer of control of the oil, the differentials are included in oil sales on the 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 ~~two~~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 ~~more owners have~~(iii) a hybrid of percentage of proceeds and fee-based contracts. Under the ~~right~~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 ~~take production “in-kind”~~natural gas processing plants where natural gas liquid products are extracted. The natural gas liquid products and remaining residue gas are then sold by the purchaser. Under the percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, the Company receives a percentage of the value for the extracted liquids and the residue gas. Under the fee-based contracts, the Company receives natural gas liquids and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those activities, revenue is recognized on a gross basis, and the related costs are classified in ~~doing so, take more or less than their respective entitled percentage. Imbalances are tracked by well; however,~~gathering, processing and transportation on the Company’s consolidated statements of operations.

The Company does not ~~record any receivable from or payable~~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 606-10-50-14A, applies to variable consideration that is recognized as control of the product is transferred to the ~~other owners unless the imbalance has reached~~customer. Since each unit of product represents a level at which it exceeds the remaining reserves in the respective well. If reserves are insufficient to offset the imbalance and the Company is in an overtake position, a liability is recorded for the amount of shortfall

F-10

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

~~in reserves valued at a contract~~

separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price ~~or the market price in effect at the time the imbalance~~allocated to remaining performance obligations is ~~generated. If the Company is in an undertake position, a receivable is recorded for an amount that is reasonably expected to be received,~~ not ~~to exceed the current market value of such imbalance. The Company had no significant imbalances at December 31, 2017 or 2016.~~

required.

General and administrative ~~expense~~.expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and records such reimbursements as reductions of general and administrative expense. Such fees totaled ~~approximately $~~16 $18 million, $17 $19 million and $19 $16 million for the years ended December 31, 2019, 2018 and 2017, ~~2016 and 2015,~~ respectively.

Stock-based ~~compensation.~~compensation. Stock-based compensation expense is recognized in the Company’s financial statements on an accelerated basis over the awards’ vesting periods based on their grant date fair values. Stock-based compensation awards ~~generally~~ vest over a period generally ranging from one to ~~eight~~ten years. The Company utilizes the average of the ~~grant date’s~~ high and low stock prices ~~for~~at each grant date to determine the fair value of restricted stock and the Monte Carlo simulation method ~~for~~to determine the fair value of performance unit awards.

The Company recognizes forfeitures on stock-based compensation awards as they occur.

Recently adopted accounting pronouncements.~~The Company adopted~~In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvements to Employee Share-based Payment Accounting,” on January 1, 2017. The adoption did not have an impact on prior period 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. Additionally, the Company recognized all excess tax benefits not previously recorded, which totaled approximately $5 million at December 31, 2016. Upon adoption, 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, and decreased net deferred income tax liabilities by approximately $8 million. The Company elected to prospectively classify excess tax benefits and deficiencies as operating activities on the consolidated statements of cash flows and will prospectively record those excess tax benefits and deficiencies as discrete items in the income tax provision in the consolidated statements of operations. Under the new standard, for the year ended December 31, 2017, the Company recorded excess tax benefits of approximately $6 million in the Company’s income tax provision. Also under the new standard, for the year ended December 31, 2017, the Company recorded actual forfeitures of share-based payments of approximately $8 million.

~~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 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 has completed its evaluation and implementation of ASU No. 2014-09 and will adopt the new revenue recognition guidance during the first quarter of 2018. The Company has elected to use the modified retrospective method for adoption. Upon adoption, the Company will not record a material cumulative effect adjustment and prior period financial statements will not be restated. The adoption of this guidance is not expected to have an ongoing material impact on the Company’s financial statements. More specifically, the adoption of this guidance will result in changes to sales of oil and natural gas and operating expenses due to the conclusion that some third-parties meet the definition of an agent under the control model in ASC 606, thus the fees paid to these service providers will be classified as operating expenses under ASC 606. With the adoption, the Company has updated its revenue recognition policy and its related internal control documentation, processes and controls to conform to the new standard. The Company will also expand its revenue recognition related disclosures.

~~In February 2016, the FASB issued ASU No.~~ 2016-02, “Leases (Topic 842),” (“ASU 2016-02”), which ~~supersedes current lease guidance. The new lease standard~~ requires all leases with a term greater than one year to be recognized on the consolidated balance sheet while maintaining ~~substantially~~ similar classifications for ~~financing~~finance and operating leases. Lease expense recognition on the consolidated statements of operations ~~will be~~was effectively unchanged. ~~This guidance is effective for reporting periods beginning after December 15, 2018, and early adoption is permitted.~~ The Company ~~does~~adopted this guidance on January 1, 2019. The Company made policy elections not ~~plan~~ to ~~early adopt~~capitalize short-term leases for all asset classes and not to separate non-lease components from lease components for all asset classes except for vehicles. The Company also did not elect the package of practical expedients that allowed for certain considerations under the original “Leases (Topic 840)” accounting standard (“Topic 840”) to be carried forward upon adoption of ASU 2016-02.

In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient not to evaluate land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under Topic 840. The Company enters into land easements on a routine basis as part of its ongoing operations and has many such agreements currently in place; however, the Company did not account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, the Company elected this practical expedient, which became effective upon the date of adoption of ASU 2016-02. The Company will assess any new land easements to determine whether the arrangement should be accounted for as a lease. In July 2018, the FASB issued ASU No. 2018-11, “Targeted Improvements,” which provides a transition election not to restate comparative periods for the effects of applying the new lease standard. This transition election permits entities to change the date of initial application to the beginning of the year of adoption and to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings. The Company elected this transition approach, however the cumulative impact of adoption in the opening balance of retained earnings as of January 1, 2019 was 0.

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~~Upon adoption, the Company ~~is substantially complete with the process of reviewing and determining the contracts to which this new guidance applies. The Company is currently enhancing its~~

F-11

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

accounting system in order to track and calculate additional information necessary for adoption of this standard. The Company believes this new guidance will have a moderate impact to its consolidated balance sheets due to the recognitionrecognized $35 million of right-of-use assets, of which $19 million and $16 million relate to the Company’s operating and finance leases, respectively, and $37 million of associated lease ~~liabilities~~liabilities. See Note 11 for additional disclosures of the Company’s leases.

In August 2018, the SEC issued a final rule that amends certain of its disclosure requirements that have become redundant, duplicative, overlapping, outdated or superseded, in light of other disclosure requirements, U.S. GAAP or changes in the information environment. The amendments are intended to facilitate the disclosure of information to investors and simplify compliance without significantly altering the total mix of information provided to investors. The final rule amends numerous SEC rules, items and forms covering a diverse group of topics, including, but not ~~currently recognized under currently applicable guidance.~~

limited to, changes in stockholders’ equity. The final rule extends the annual disclosure requirement in SEC Regulation S-X, Rule 3-04, of presenting changes in stockholders’ equity to interim periods. Registrants are required to analyze changes in stockholders’ equity in the form of a reconciliation for the current quarter and year-to-date interim periods and comparative periods in the prior year. In addition, the final rule requires the presentation of dividends per share to be disclosed in the statement of stockholders’ equity.

New accounting pronouncements issued but not yet adopted.In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial ~~Instruments,”~~Instruments” (“Topic 326”), which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. In November 2018, the FASB issued ASU No. 2018-19, “Codification Improvements to Topic 326, Financial Instruments–Credit Losses,” which makes amendments to clarify the scope of the guidance, including the amendment clarifying that receivables arising from operating leases are not within the scope of Topic 326. This guidance is effective for fiscal years beginning after December 15, 2019. The Company has completed the process of determining which financial assets are in scope for this new guidance and has developed an internal model to measure the expected credit losses for those balances as required by the new guidance. Financial assets in scope for the Company include oil and natural gas sales receivables and joint interest receivables. The Company adopted this new

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Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and ~~early adoption~~2017

guidance on January 1, 2020 and recognized an immaterial non-cash cumulative effect adjustment to retained earnings on our opening consolidated balance sheet at the date of adoption.

In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606” (“ASU 2018-18”), which, among other things, clarifies that (i) certain transactions between collaborative arrangement participants should be accounted for as revenue under Topic 606 when the collaborative arrangement participant is ~~allowed as early as~~a customer in the context of a unit of account, (ii) adds unit-of-account guidance in Topic 808 to align with the guidance in Topic 606 and (iii) requires that in a transaction with a collaborative arrangement participant that is not directly related to sales to third parties, presenting the transaction together with revenue recognized under Topic 606 is precluded if the collaborative arrangement participant is not a customer. ASU 2018-18 is effective for fiscal years beginning after December 15, ~~2018.~~2019, and interim periods within those fiscal years. The amendments in this update should be applied retrospectively to the date of initial application of Topic 606. An entity should recognize the cumulative effect of initially applying the amendments as an adjustment to the opening balance of retained earnings of the later of the earliest annual period presented and the annual period that includes the date of the entity’s initial application of Topic 606. The Company ~~does~~adopted this guidance on January 1, 2020. The adoption did not ~~believe this new guidance will~~ have a material impact on ~~its~~the Company��s consolidated financial statements.

In ~~January 2017,~~December 2019, the FASB issued ASU No. ~~2017-01, “Business Combinations~~2019-12, “Income Taxes (Topic ~~805)~~740): ~~Clarifying~~Simplifying the ~~Definition~~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 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 activitiestransaction that is not a ~~business. The screen requires that when substantially all~~business combination; (iii) separate financial statements of entities not subject to tax; (iv) 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 contributeintraperiod tax allocation exception to the ~~ability~~incremental approach; (v) ownership changes in investments - changes from a subsidiary to ~~create output. This new guidance~~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 ~~annual periods~~fiscal years beginning after December 15, ~~2017,~~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 adopt ASU 2019-12 is required to adopt all of the amendments in the same period. The Company ~~does not believe this new guidance~~is currently assessing the effect that ASU 2019-12 will have ~~a material impact~~ on its ~~consolidated~~ financial ~~statements.~~

position, results of operations and disclosures.

F-12

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

Note 3. Exploratory well costs

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

The following table reflects the Company’s net capitalized exploratory well activity during each of the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015:~~

2017:

Years Ended December 31,
(in millions)

2017

2016

2015

Beginning capitalized exploratory well costs

$
151

$
116

$
242

Additions to exploratory well costs pending the determination of proved reserves


180

144

103

Reclassifications due to determination of proved reserves


(147)

(86)

(228)

Exploratory well costs charged to expense


-

(6)

(1)

Disposition of wells


(2)

(17)

-
Ending capitalized exploratory well costs

$
182

$
151

$
116



(in millions)	Years Ended December 31,
(in millions)	2019			2018			2017
Beginning capitalized exploratory well costs	$	523		$	182		$	151
Additions to exploratory well costs pending the determination of proved reserves (a)	271			581			180
Reclassifications due to determination of proved reserves	(503		)	(226		)	(147		)
Exploratory well costs charged to expense	(6		)	—			—
Disposition of wells	(7		)	(14		)	(2		)
Ending capitalized exploratory well costs	$	278		$	523		$	182


(a)	Balance at December 31, 2018 includes $82 million of exploratory well costs acquired as part of the RSP Acquisition, as defined in Note 4.

The following table provides an aging at December 31, ~~2017~~2019 and ~~2016~~2018 of capitalized exploratory well costs based on the date drilling was completed:


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

(in millions, except number of projects)						2019		2018
(in millions, except number of projects)	Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	180	$	141	$	263	$	523
Capitalized exploratory well costs that have been capitalized for a period greater than one year	Capitalized exploratory well costs that have been capitalized for a period greater than one year		2		10	15		—
Total capitalized exploratory well costs						$	278	$	523
Number of projects with exploratory well costs that have been capitalized for a period greater than one year						2		—
	Total capitalized exploratory well costs	$	182	$	151
Number of projects with exploratory well costs that have been capitalized for a period greater
	than one year		2		8

F-13

The Company expects to complete 3 gross wells associated with 2 projects with $15 million of capitalized exploratory well costs greater than one year at December 31, 2019 in early 2020.

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Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

Note 4. RSP Acquisition

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

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

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

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

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

(in millions)

Total purchase price $ 7,549

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

Total purchase price plus liabilities assumed $ 10,100

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

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

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

Oil and natural gas properties

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

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

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

Financial instruments and other

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

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

Other current liabilities include $10 million of liabilities primarily related to certain regulatory obligations.

Deferred income taxes

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

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

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

Pro forma data.The following unaudited pro forma combined condensed financial data for the years ended December 31, 2018 and 2017 was derived from the historical financial statements of the Company giving effect to the RSP Acquisition, as if it had occurred on January 1, 2017. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for RSP’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert RSP’s outstanding shares of common stock and equity awards as of the closing date of the RSP Acquisition, (ii) the depletion of RSP’s fair-valued proved oil and gas properties and (iii) the estimated tax impacts of the pro forma adjustments.

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Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of $32 million for the year ended December 31, 2018 and acquisition-related costs incurred by RSP and severance payments to certain RSP employees that totaled $56 million for the year ended December 31, 2018. The pro forma results of operations do not include any cost savings or other synergies that may result from the RSP Acquisition. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the period. The pro forma combined condensed financial data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the RSP Acquisition taken place on January 1, 2017 and is not intended to be a projection of future results.

(in millions, except per share amounts) Years Ended December 31,
2018 2017
(unaudited)
Operating revenues $ 4,798
$ 3,390
Net income $ 2,552
$ 1,197
Earnings per share:
Basic net income $ 12.75
$ 6.02
Diluted net income $ 12.73
$ 5.99

Note 5. Acquisitions, divestitures and nonmonetary transactions

During the year ended December 31, 2019, the Company closed on the following transactions:

New Mexico Shelf divestiture. On August 29, 2019, the Company entered into a definitive agreement to sell its assets in the New Mexico Shelf. The Company determined these assets and liabilities to be held for sale at August 29, 2019 and recorded an impairment charge of $3 million, included in impairments of long-lived assets on the Company’s consolidated statement of operations for the year ended December 31, 2019, to reduce the carrying value of these assets to their estimated fair value less costs to sell. This transaction closed in November 2019 for total proceeds of $837 million, subject to post-closing adjustments. The Company recorded a pre-tax loss of $27 million, included in gain on disposition of assets, net on the Company’s consolidated statement of operations for the year ended December 31, 2019. Additionally, the Company impaired the carrying value of goodwill by $81 million, reflecting the portion of the Company’s goodwill allocated to the assets sold.

Nonmonetary transactions.During 2019, the Company completed multiple nonmonetary transactions. These transactions included exchanges of both proved and unproved oil and natural gas properties. Certain of these transactions were accounted for at fair value and, as a result, the Company recorded net pre-tax losses of $104 million, including a $23 million reduction of the carrying value of goodwill, reflecting the portion of the Company’s goodwill related to the assets sold.

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

February 2018 acquisition and divestiture.In February 2018, the Company closed on an acquisition treated as a business combination where it received producing wells with approximately 21,000 net acres, primarily located in the Midland Basin. As consideration for the non-cash acquisition, the Company divested approximately 34,000 net acres located primarily in the northern portion of the Delaware Basin. The business acquired was valued at approximately $755 million as compared to the historical book value of the divested assets of approximately $180 million, which resulted in a non-cash gain of approximately $575 million, included in gain on disposition of assets, net on the Company’s consolidated statement of operations for the year ended December 31, 2018. The fair value of the assets acquired totaled approximately $755 million, which was comprised of approximately $245 million of proved properties, approximately $480 million of unproved properties and approximately $30 million of other assets. The fair value of the assets received in the business combination approximated the fair value of assets disposed.

Delaware Basin divestitures.In January 2018, the Company closed on two asset sales transactions of certain non-core assets in Reeves and Ward Counties, Texas, with combined proceeds of approximately $280 million. After direct transaction costs, the Company recorded a pre-tax gain of approximately $134 million, which is included in gain on disposition of assets, net on its consolidated statement of operations for the year ended December 31, 2018. The assets divested included proved and unproved oil and natural gas properties on approximately 20,000 net acres.

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

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

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

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

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

~~Northern~~

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

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

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

Concurrent with the acquisition, the Company entered into a transaction structured as a ~~reverse like-kind exchange (“~~Reverse 1031 ~~Exchange”) in accordance with Section 1031 of the Internal Revenue Code of 1986, as amended (the “Code”).~~Exchange. In connection with the Reverse 1031 Exchange, the Company assigned the ownership of the oil and natural gas properties acquired to a VIE formed by an exchange accommodation titleholder. The Company ~~operates~~operated the properties pursuant to a management agreement with the VIE. At December 31, 2017, the Company was determined to be the primary beneficiary of the VIE, as the Company had the ability to control the activities that most significantly impact the VIE’s economic performance. The assets ~~currently~~ held by the VIE attributable to the acquisition ~~will be~~were conveyed to the Company ~~or one of its subsidiaries,~~ and the VIE structure ~~will terminate,~~terminated 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 December 31, 2017, the VIE’s total assets and liabilities included in the Company’s consolidated balance sheet were approximately $608 million and $604 million, respectively. See Note 17 for further discussion of the subsequent event that completed the Reverse 1031 Exchange.

Nonmonetary transactions.During 2017, the Company completed multiple nonmonetary transactions. The transactions ~~include the exchange~~included exchanges of both proved and unproved oil and natural gas properties. Certain of these transactions were accounted for at fair value and as a result the Company recorded pre-tax gains oftotaling approximately $26 million.

~~During the year ended December 31, 2016, the Company entered into the following transactions:~~

~~Asset divestiture.~~ ~~In February 2016, the Company sold certain assets in the northern Delaware Basin for proceeds~~

Table of ~~approximately $292 million and recognized a pre-tax gain of approximately $110 million.~~

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

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

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

F-14

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

~~The following table reflects the fair value of the acquired assets and liabilities at the October 2016 closing date associated with the Reliance Acquisition:~~

(in millions)

Fair value of net assets:

Proved oil and natural gas properties

$
730

Unproved oil and natural gas properties


972

Other assets

34

Total assets acquired

1,736

Current liabilities, including current portion of asset retirement obligations


(8)

Asset retirement obligations assumed

(12)

Fair value of net assets acquired

$
1,716



Fair value of consideration paid for net assets:

Cash consideration

$
1,176

Non-cash consideration, including equity

540

Total consideration paid for net assets

$
1,716

~~Pro forma data.~~ The following unaudited pro forma combined condensed financial data for the year ended December 31, 2016 was derived from the historical financial statements of the Company giving effect to the Reliance Acquisition, as if it had occurred on January 1, 2016. The results of operations for the Reliance Acquisition are included in the Company’s results of operations since the closing date in October 2016 through December 31, 2017. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material. The unaudited pro forma combined condensed financial data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Reliance Acquisition taken place as of the date indicated and is not intended to be a projection of future results.

Year Ended
(in millions, except per share amounts)

December 31, 2016

(unaudited)

Operating revenues

$
1,717
Net loss

$
(1,396)
Earnings per common share:


Basic net loss

$
(10.36)

Diluted net loss

$
(10.36)

~~During the year ended December 31, 2015, the Company entered into the following transaction:~~

~~Clayton Williams Acreage Exchange.~~ In December 2015, the Company completed a nonmonetary acreage exchange with Clayton Williams Energy, Inc. that consolidated acres into a concentrated, operated position in the southern Delaware Basin. The Company recognized a loss on disposition of assets of approximately $50 million related to the acreage exchange based on the fair value of the assets surrendered.

F-15

2017

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

Note 5. 6. Asset retirement obligations

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

The Company’s asset retirement obligation transactions during the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~2017 are summarized in the table below:



(in millions)	Years Ended December 31,
(in millions)	2019			2018			2017
Asset retirement obligations, beginning of period	$	179		$	141		$	130
Liabilities incurred from new wells	7			4			2
Liabilities assumed in acquisitions	4			26			10
Accretion expense	10			10			8
Disposition of wells	(66		)	(4		)	(1		)
Liabilities settled upon plugging and abandoning wells	(7		)	(7		)	(5		)
Revision of estimates (a)	12			9			(3		)
Asset retirement obligations, end of period	$	139		$	179		$	141


(a)	The revisions to the Company’s asset retirement obligation estimates for the years ended December 31, 2019 and 2018 were primarily due to increased costs in New Mexico.

Years Ended December 31,
(in millions)

2017

2016

2015

Asset retirement obligations, beginning of period

$
130

$
120

$
120

Liabilities incurred from new wells


2


2


4

Liabilities assumed in acquisitions


10


13


2

Accretion expense


8


7


8

Disposition of wells

(1)

(11)

-

Liabilities settled upon plugging and abandoning wells


(5)


(1)


(3)

Revision of estimates (a)


(3)


-


(11)
Asset retirement obligations, end of period

$
141

$
130

$
120

(a)
The revisions to the Companyʼs asset retirement obligation estimates for the years ended December 31, 2017 and 2015 are primarily due to a reduction in the future estimated abandonment costs.

F-16

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

Note 6.7. Incentive plans

Defined contribution plan.The Company sponsors a 401(k) defined contribution plan for the benefit of its employees. During the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015,~~2017, the Company matched 100 percent of employee contributions, not to exceed 10 percent of the employee’s annual eligible compensation, subject to federal limits. The Company’s contributions to the plan for the years ended December 31, 2019, 2018 and 2017 ~~2016 and 2015~~ were ~~approximately $10~~$15 million, $9$12 million and $10 million, ~~respectively, of which a portion was recoverable from other working interest owners.~~

respectively.

Stock incentive plan.~~The~~On May 16, 2019, the Company’s ~~2015~~stockholders approved and adopted the Company’s 2019 Stock Incentive Plan ~~(the “Plan”) provides for granting stock options, restricted stock awards and performance awards to directors, officers and employees of~~ (“the ~~Company. A~~Plan”), which, among other things, increased the total ~~of 10.5 million~~ shares ~~of common stock have been~~ authorized for issuance ~~under the Plan.~~from 10.5 million to 15.0 million. At December 31, ~~2017,~~2019, the Company had ~~2.1~~5.0 million shares of common stock available for future grants. Shares issued as a result of awards granted under the Plan are generally new common shares.

Restricted stock awards.All restricted shares are legally issued and outstanding. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and ~~cancelled~~canceled and are no longer considered issued and outstanding. A summary of the Company’s restricted stock award activity for the year ended December 31, ~~2017~~2019 is presented below:

Weighted

Average

Number of

Grant Date

Restricted

Fair Value

Shares

Per Share

Restricted stock:

Outstanding at December 31, 2016

1,157,270

$
115.29

Shares granted

490,300

$
123.16

Shares cancelled / forfeited

(100,199)

$
113.56

Lapse of restrictions

(398,125)

$
117.91

Outstanding at December 31, 2017

1,149,246

$
118.02

F-17

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~



	Number of Restricted Shares		Weighted Average Grant Date Fair Value Per Share
Outstanding at December 31, 2018	1,364,699		$	128.08
Shares granted	776,189		$	98.83
Shares cancelled / forfeited	(147,336	)	$	113.69
Lapse of restrictions	(508,200	)	$	126.82
Outstanding at December 31, 2019	1,485,352		$	113.74

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

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

The following table summarizes information about stock-based compensation for the Company’s restricted stock awards activity under the Plan for ~~years ended December 31, 2017, 2016 and 2015:~~

Years Ended December 31,

(in millions)

2017

2016

2015

Fair value for awards granted during the period (a)

$
60

$
51

$
50

Fair value for awards vested during the period

$
49

$
45

$
36

Stock-based compensation expense from restricted stock

$
43

$
41

$
43

Income tax benefit related to restricted stock

$
11

$
15

$
16

(a)
The weighted average grant date fair value per share amounts were $123.16, $112.78 and $109.76 for the years ended December 31, 2017, 2016 and 2015, respectively.

During the year ended December 31, 2017, the Company recorded actual forfeitures of $8 million which reduced total stock-based compensation expense. During the year ended December 31, 2016, the Company recorded $5 million of estimated forfeitures.

~~Stock option awards.~~ ~~A summary of the Company’s stock option award activity under the Plan for the year ended December 31, 2017 is presented below:~~

Weighted

Average

Number of

Exercise

Options

Price

Stock options:

Outstanding at December 31, 2016

20,000

$
15.33

Options exercised

(20,000)

$
15.33

Outstanding at December 31, 2017

-

Vested and exercisable at December 31, 2017

-

~~The intrinsic value of options exercised~~ ~~was approximately $2 million for each of~~ the years ended December 31, ~~2017~~2019, 2018 and 2016 based on the difference between the market price at the exercise date and the option exercise price. The Company did not have any material options exercised during the year ended December 31, 2015.

2017:

F-18



(in millions)	Years Ended December 31,
(in millions)	2019		2018		2017
Fair value for awards granted during the period (a)	$	77	$	94	$	60

Fair value for awards vested during the period	$	52	$	54	$	49

Stock-based compensation expense from restricted stock	$	63	$	60	$	43

Income tax benefit related to restricted stock	$	10	$	14	$	11


(a)	The weighted average grant date fair value per share amounts were $98.83, $137.31 and $123.16 for the years ended December 31, 2019, 2018 and 2017, respectively.

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

Performance unit awards.During the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015,~~2017, the Company awarded performance units to its officers under the Plan. The number of shares of common stock that will ultimately be issued will be determined by a combination of (i) comparing the Company’s total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. ~~The~~Other than the performance units with a five-year performance period described below, the performance period is ~~36 months.~~ typically 3 years.

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

The grant date fair value ~~was~~is determined using the Monte Carlo simulation method and is ~~being~~ expensed ratably over the performance period. Expected volatilities utilized in the model were estimated using a historical period consistent with the remaining performance ~~period of approximately three years.~~period. The risk-free interest rate was based on the U.S. Treasury rate for a term commensurate with the expected life of the grant.

The Company used the following assumptions to estimate the fair value of performance unit awards granted during the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015:~~2017:



	Years Ended December 31,
	2019	2018	2017
Risk-free interest rate	2.45% - 2.47%	2.00%	1.47%
Range of volatilities	23.3% - 50.0%	23.5% - 64.0%	24.8% - 60.2%

Table of Contents

Years Ended December 31,

2017

2016

2015

Risk-free interest rate
1.47%

1.31%

1.07%
Range of volatilities
24.8% - 60.2%

31.6% - 59.0%

26.1% - 43.0%

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

The following table summarizes the performance unit activity for the year ended December 31, ~~2017:~~

2019:

Number of

Grant Date

Units

Fair Value

Performance units:

Outstanding at December 31, 2016

331,526

$
136.68

Units granted (a)

108,398

$
183.48

Units forfeited

(43,333)

$
140.00

Units vested (b)

(148,944)

$
156.86

Outstanding at December 31, 2017

247,647

$
146.10

(a)
Reflects the amount of performance units granted. The actual payout of shares will be between zero and 300 percent of the performance units granted depending on the Company’s performance at the end of the performance period.

(b)
On December 31, 2017, the performance period ended for these performance units. Each unit converted into three shares representing 446,832 shares of common stock issued on January 2, 2018.

F-19



	Number of Units		Grant Date Fair Value
Performance units:
Outstanding at December 31, 2018	218,391		$	201.97
Units granted (a)	212,947		$	144.03
Lapse of restrictions (b)	(106,901	)	$	187.31
Outstanding at December 31, 2019	324,437		$	168.77


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


(b)	On December 31, 2019, the performance period ended for these performance units. Each unit converted into 0.38 shares representing 40,631 shares of common stock issued on January 2, 2020.

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

The following table summarizes information about stock-based compensation expense for performance units for the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015:~~

2017:

Years Ended December 31,
(in millions)

2017

2016

2015

Fair value for awards granted during the period (a)

$
20

$
19

$
28

Fair value for awards vested during the period

$
68

$
33

$
16

Stock-based compensation expense from performance units

$
17

$
18

$
20

Income tax benefit related to performance units

$
2

$
7

$
7

(a)
The weighted average grant date fair value per unit amounts were $183.48, $114.81 and $156.86 for the years ended December 31, 2017, 2016 and 2015, respectively.

(in millions) Years Ended December 31,
2019 2018 2017
Fair value for awards granted during the period (a) $ 31
$ 24
$ 20

Fair value for awards vested during the period $ 26
$ 68
$ 68

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

Income tax benefit related to performance units $ 5
$ 14
$ 2


(a)	The weighted average grant date fair value per unit amounts were $144.03, $216.03 and $183.48 for the years ended December 31, 2019, 2018 and 2017, respectively.

Future stock-based compensation expense.The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at December 31, ~~2017:~~

2019:



(in millions)	(in millions)
2020				$	61
2021				36
2022				12
2023				2
2024				1
Thereafter				2
Total				$	114

2018		$	49
2019			26
2020			8
Thereafter			2
	Total	$	85

F-20

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

Note 7. 8. Disclosures about fair value measurements

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

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

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

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


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

Level 2:

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

Level 3:

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

F-21

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

Financial Assets and Liabilities Measured at Fair Value

The following table presents the carrying amounts and fair values of the Company’s financial instruments at December 31, ~~2017~~2019 and ~~2016:~~

2018:

December 31, 2017

December 31, 2016

Carrying

Fair

Carrying

Fair
(in millions)

Value

Value

Value

Value

Assets:

Derivative instruments

$
-

$
-

$
4

$
4

Liabilities:

Derivative instruments

$
379

$
379

$
178

$
178

Credit facility

$
322

$
322

$
-

$
-

$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

$
624

$
592

$
599

$1,000 million 3.75% senior notes due 2027 (a)

$
987

$
1,012

$
-

$
-

$800 million 4.875% senior notes due 2047 (a)

$
789

$
874

$
-

$
-

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

(in millions) December 31, 2019 December 31, 2018
Carrying
Value

Fair
Value

Carrying
Value

Fair
Value
Assets:
Derivative instruments $ 17
$ 17
$ 695
$ 695

Liabilities:
Derivative instruments $ 119
$ 119
$ —
$ —
Credit facility $ —
$ —
$ 242
$ 242
$600 million 4.375% senior notes due 2025 (a) $ 595
$ 620
$ 594
$ 591
$1,000 million 3.75% senior notes due 2027 (a) $ 990
$ 1,054
$ 989
$ 939
$1,000 million 4.3% senior notes due 2028 (a) $ 989
$ 1,091
$ 988
$ 980
$800 million 4.875% senior notes due 2047 (a) $ 789
$ 941
$ 789
$ 761
$600 million 4.85% senior notes due 2048 (a) $ 592
$ 697
$ 592
$ 573


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

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

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

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

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.

F-22

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification,even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at December 31, ~~2017~~2019 and ~~2016.~~2018. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.

December 31, 2017

Fair Value Measurements Using

Net

Quoted Prices

Gross

Fair Value

in Active

Significant

Amounts

Presented

Markets for

Other

Significant

Offset in the

in the

Identical

Observable

Unobservable

Total

Consolidated

Consolidated

Assets

Inputs

Inputs

Fair

Balance

Balance
(in millions)
(Level 1)

(Level 2)

(Level 3)

Value

Sheet

Sheet

Assets

Current:

Commodity derivatives

$
-

$
13

$
-

$
13

$
(13)

$
-

Noncurrent:

Commodity derivatives

-


1


-


1


(1)


-

Liabilities

Current:

Commodity derivatives

-

(290)

-

(290)

13

(277)

Noncurrent:

Commodity derivatives

-


(103)


-


(103)


1


(102)

Net derivative instruments

$
-

$
(379)

$
-

$
(379)

$
-

$
(379)

F-23



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

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

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

Total

Consolidated

Consolidated

Assets

Inputs

Inputs

Fair

Balance

Balance
(in millions)
(Level 1)

(Level 2)

(Level 3)

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)

December 31, 2018
Fair Value Measurements Using
Total
Fair
Value

Gross
Amounts
Offset in the
Consolidated
Balance
Sheet

Net
Fair Value
Presented
in the
Consolidated
Balance
Sheet
(in millions)
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Assets
Current:
Commodity derivatives $ —
$ 543
$ —
$ 543
$ (59 ) $ 484
Noncurrent:
Commodity derivatives —
243
—
243
(32 ) 211

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

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

Concentrations of credit risk.At December 31, ~~2017,~~2019, the Company’s primary concentrations of credit risk are the risk of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations. See Note 1213 for information regarding the Company’s major customers and derivative counterparties.

The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 89 for additional information regarding the Company’s derivative activities.

F-24

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

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

At June 30, 2019, the carrying amount of the proved properties of the Company’s Yeso field exceeded the expected undiscounted future net cash flows resulting in an impairment charge against earnings of $868 million, reducing the carrying value of the Yeso field to its estimated fair value of $968 million. This impairment charge represented the amount by which the carrying amount exceeded the estimated fair value of the assets and was attributable primarily to certain downward adjustments to the Company’s economically recoverable proved oil and natural gas reserves. Additionally, during the third quarter of 2019, the Company further impaired the Yeso Field due to the decrease in future commodity prices and recorded an additional impairment charge of $20 million. These impairment charges were included in impairments of long-lived assets on the consolidated statement of operations for the year ended December 31, 2019.

At December 31, 2019, the expected undiscounted future net cash flows were greater than the carrying amounts of the Company’s assets and no additional impairment was recorded.

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

The assumptions used in calculating the estimated fair value of the Yeso field at June 30, 2019 and the Company’s assets at December 31, 2019 are below.

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”)~~NYMEX strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, and (vii) prevailing market rates of income and expenses from integrated assets.

At June 30, 2019, the Company’s estimates of commodity prices for purposes of determining undiscounted future cash flows, which were based on the NYMEX strip, ranged from a 2019 price of $58.32 per barrel of oil decreasing to a 2022 price of $53.58 then rising to a 2026 price of $54.47 per barrel of oil. Natural gas prices ranged from a 2019 price of $2.38 per Mcf of natural gas increasing to a 2026 price of $2.99 per Mcf. Both oil and natural gas commodity prices for this purpose were held flat after 2026.

AtDecember 31, ~~2017~~,2019, the Company’s estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a ~~2018~~2020 price of ~~$59.55~~$58.83 per barrel of oil decreasing to a ~~2024~~2023 price of ~~$51.82~~$51.31 per barrel of oil ~~marginally recovering~~then rising to a ~~2025~~2026 price of ~~$51.83~~$52.57 per barrel of oil. ~~Similarly, natural~~Natural gas prices ranged from a ~~2018~~2020 price of ~~$2.84~~$2.29 per Mcf of natural gas ~~decreasing~~increasing to a ~~2019~~2026 price of ~~$2.81 per Mcf then rising to a 2025 price of $2.99~~$2.55 per Mcf of natural gas. Both oil and natural gas commodity prices for this purpose were held flat after ~~2025.~~2026. The Company did not recognize any impairment loss during the ~~year~~years ended December 31, 2018 or 2017.

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

At June 30, 2019, the Company’s estimate 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 2019 price of $58.32 per barrel of oil increasing to a 2026 price of $62.06 per barrel of oil. Natural gas prices ranged from a 2019 price of $2.38 per Mcf of natural gas increasing to a 2026 price of $3.00 per Mcf of natural gas. These prices were then adjusted for location and ~~risk-adjusted probable~~quality differentials. Both oil and ~~possible reserves, (vii) prevailing market rates of income and expenses from integrated assets and (viii) discount rate.~~natural gas commodity prices for this purpose were inflated by 2 percent each year after 2026. 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.~~

~~During the three months ended March 31, 2016, NYMEX strip prices declined as compared to~~percent.

At December 31, ~~2015, and as a result the carrying amount of~~2019, the Company’s ~~Yeso field~~estimate of ~~approximately $3.4 billion exceeded the~~commodity prices for purposes of determining discounted future cash flows ranged from a 2020 price of $58.83 per barrel of oil decreasing to a 2021 price of $54.38 per barrel of oil then rising to a 2026 price of $59.01 per barrel of oil. Natural gas prices ranged from a 2020 price of $2.29 per Mcf of natural gas increasing to a 2026 price of $2.63 per Mcf of natural gas. These prices were then adjusted for location and quality differentials. Both oil and natural gas commodity prices for this purpose were inflated by 2 percent each year after 2026. The expected ~~undiscounted~~ future net cash flows ~~resulting in~~were discounted using a ~~non-cash charge against earnings~~rate of ~~approximately~~ ~~$1.5~~ ~~billion. The non-cash charge represented the amount by which the carrying amount exceeded the estimated fair value of the assets.~~

~~The following table reports the carrying amount, estimated fair value and impairment expense of long-lived assets for the indicated periods:~~

10 percent.

Estimated

Carrying

Fair Value

Impairment
(in millions)

Amount

(Level 3)

Expense

March 2016

$
3,438

$
1,913

$
1,525
December 2015

$
105

$
52

$
53
September 2015

$
18

$
10

$
8

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

F-25

Assets held for sale. The Company’s Yeso field was primarily composed of the New Mexico Shelf assets that the Company sold in November 2019. The assets and liabilities associated with the New Mexico Shelf divestiture were classified as held for sale at August 29, 2019 and were measured at their estimated fair value less cost to sell. The related fair value at August 29, 2019 was based upon anticipated sales proceeds less costs to sell. Because the Company’s closing and post-closing adjustments, primarily revenues and operating expenses, used to calculate the fair value less costs to sell were estimates that were both significant and unobservable, they were considered Level 3 fair value measurements. This transaction closed in November 2019 for total proceeds of $837 million, subject to additional post-closing adjustments. Refer to Note 5 for additional information related to the New Mexico Shelf asset divestiture.

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

Note 8. 9. Derivative financial instruments

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

At December 31, 2019, the Company’s derivative financial instruments consisted of oil and natural gas swaps and basis swaps. Swap contracts allow the Company to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. Basis swap contracts allow the Company to receive a fixed price differential between market indices for the price of oil or natural gas.

In connection with the RSP Acquisition, the Company assumed certain oil collar and three-way collar contracts. In these contracts, each collar has an established floor price and ceiling price, and certain collars also include a short put price (three-way collars). When the settlement price is below the established floor price, the Company receives an amount from its counterparty equal to the difference between the settlement price and the floor price multiplied by the hedged contract volume. When the settlement price is above the established ceiling price, the Company pays its counterparty an amount equal to the difference between the settlement price and the ceiling price multiplied by the hedged contract volume. When the settlement price is between the established floor and the ceiling, no amounts are due to or from the counterparty. In case of a three-way collar, when the settlement price is below the short put price, the Company receives from its counterparty an amount equal to the difference of the floor price and the short put price multiplied by the hedged contract volume. The Company had no outstanding collars or three-way collars at December 31, 2019.

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 years endedDecember 31, ~~2017, 2016~~2019, 2018and ~~2015:~~

2017:

Years Ended December 31,

(in millions)

2017

2016

2015

Gain (loss) on derivatives:

Oil derivatives

$
(172)

$
(337)

$
675

Natural gas derivatives

46

(32)

25

Total

$
(126)

$
(369)

$
700

     The following table represents the Company’s net cash receipts from derivatives for the years ended December 31, 2017, 2016 and 2015:

Years Ended December 31,

(in millions)

2017

2016

2015

Net cash receipts from derivatives:

Oil derivatives

$
79

$
609

$
597

Natural gas derivatives


-


16


36

Total

$
79

$
625

$
633

F-26



(in millions)	Years Ended December 31,
(in millions)	2019			2018			2017
Gain (loss) on derivatives:
Oil derivatives	$	(1,003	)	$	848		$	(172	)
Natural gas derivatives	108			(16		)	46
Total	$	(895	)	$	832		$	(126	)

The following table represents the Company’s net cash receipts from (payments on) derivatives for the years ended December 31, 2019, 2018 and 2017:



(in millions)	Years Ended December 31,
(in millions)	2019			2018			2017
Net cash receipts from (payments on) derivatives:
Oil derivatives	$	(129	)	$	(213	)	$	79
Natural gas derivatives	31			(5		)	—
Total	$	(98	)	$	(218	)	$	79

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

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

2021.

First

Second

Third

Fourth

Quarter

Quarter

Quarter

Quarter

Total

Oil Price Swaps: (a)


2018:










Volume (Bbl)

10,123,629

8,965,170

7,931,318

7,432,007

34,452,124

Price per Bbl
$
52.05
$
51.92
$
51.65
$
51.57
$
51.82

2019:










Volume (Bbl)

6,613,000

6,254,500

5,946,000

5,681,000

24,494,500

Price per Bbl
$
52.36
$
52.33
$
52.37
$
52.36
$
52.35
Oil Basis Swaps: (b)

2018:


Volume (Bbl)

10,059,000

8,855,000

8,066,000

7,451,000

34,431,000

Price per Bbl
$
(0.80)
$
(0.88)
$
(0.89)
$
(0.93)
$
(0.87)

2019:


Volume (Bbl)

6,870,000

6,505,500

6,210,000

5,933,000

25,518,500

Price per Bbl
$
(0.96)
$
(0.98)
$
(0.99)
$
(1.01)
$
(0.98)
Natural Gas Price Swaps: (c)

2018:


Volume (MMBtu)

16,556,000

16,101,000

14,819,000

14,504,000

61,980,000

Price per MMBtu
$
3.05
$
3.04
$
3.04
$
3.03
$
3.04

2019:


Volume (MMBtu)

4,591,533

4,501,387

4,418,537

4,329,535

17,840,992

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.



	2020
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total			2021
Oil Price Swaps – WTI: (a)
Volume (MBbl)	14,674			12,494			11,080			10,045			48,293			18,612
Price per Bbl	$	57.13		$	56.90		$	56.88		$	57.00		$	56.98		$	54.19
Oil Price Swaps – Brent: (b)
Volume (MBbl)	2,578			2,031			1,768			1,503			7,880			—
Price per Bbl	$	60.78		$	60.33		$	60.29		$	60.14		$	60.43		$	—
Oil Basis Swaps: (c)
Volume (MBbl)	14,951			11,284			10,856			10,120			47,211			18,980
Price per Bbl	$	(0.43	)	$	(0.56	)	$	(0.62	)	$	(0.71	)	$	(0.57	)	$	0.64
Natural Gas Price Swaps – Henry Hub: (d)
Volume (BBtu)	35,023			32,314			30,038			28,498			125,873			40,150
Price per MMBtu	$	2.46		$	2.46		$	2.47		$	2.47		$	2.47		$	2.52
Natural Gas Basis Swaps – Henry Hub/El Paso Permian: (e)
Volume (BBtu)	25,770			23,960			22,080			21,770			93,580			36,500
Price per MMBtu	$	(1.06	)	$	(1.07	)	$	(1.07	)	$	(1.07	)	$	(1.07	)	$	(0.66	)
Natural Gas Basis Swaps – Henry Hub/WAHA: (f)
Volume (BBtu)	7,280			7,280			7,360			7,360			29,280			10,950
Price per MMBtu	$	(1.10	)	$	(1.10	)	$	(1.10	)	$	(1.10	)	$	(1.10	)	$	(0.66	)


(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.

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

In September 2017, the Company elected to enter into an “Investment Grade ~~Period”~~Period,” as defined in Note 10, under the Credit Facility, ~~as defined below,~~ which had the effect of releasing all collateral formerly securing the Credit Facility. Additionally, as a result of the Company’s Investment Grade Period election along with amendments to certain ISDA Agreements with the Company’s derivative counterparties, the Company’s derivatives are no longer secured. See Note 910 for additional information regarding the Credit Facility.

F-27

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

Note 9. 10.Debt

The Company’s debt consisted of the following at December 31, ~~2017~~2019 and ~~2016:~~

2018:

December 31,

(in millions)

2017

2016

Credit facility

$
322

$
-

5.5% unsecured senior notes due 2022


-


600

5.5% unsecured senior notes due 2023


-


1,550

4.375% unsecured senior notes due 2025 (a)


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

(25)


(31)

Less: current portion


-


-

Total long-term debt

$
2,691

$
2,741

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

(in millions) December 31,
2019 2018
Credit facility due 2022 $ —
$ 242
4.375% unsecured senior notes due 2025 (a) 600
600
3.75% unsecured senior notes due 2027 1,000
1,000
4.3% unsecured senior notes due 2028 1,000
1,000
4.875% unsecured senior notes due 2047 800
800
4.85% unsecured senior notes due 2048 600
600
Unamortized original issue discount (9 ) (10 )
Senior notes issuance costs, net (36 ) (38 )
Less: current portion —
—
Total long-term debt $ 3,955
$ 4,194


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

Credit ~~facility.~~ Facility.The ~~Company’s credit facility, as amended and restated (the “Credit Facility”),~~Credit Facility has a maturity date of May 9, ~~2022.~~2022. At December 31, ~~2017,~~2019, the Company’s commitments from its bank group were $2.0 billion.

In April 2017, the Company amended the Credit Facility to extend the maturity date ~~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 for the proportional amount of unamortized deferred loan costs associated with banks that are no longer in the Credit Facility syndicate as a result of the April 2017 amendment.

In September 2017, the Company elected to enter into an Investment Grade Period under the Credit Facility, which had the effect of releasing all collateral formerly securing the Credit Facility. If the Investment Grade Period under the Credit Facility terminates (whether automatically due to a downgrade of the Company’s credit ratings below certain thresholds or by the Company’s election), the Credit Facility will once again be secured by a first lien on substantially all of the Company’s oil and natural gas properties and by a pledge of the equity interests in its subsidiaries. At December 31, ~~2017,~~2019, certain 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 ~~(4.50~~(4.8 percent at December 31, ~~2017)~~2019), (b) the federal funds effective rate plus 0.5 percent and (c) ~~the London Interbank Offered Rate (“LIBOR”)~~LIBOR plus 1.0 percent or (ii) LIBOR. The Credit Facility’s interest rates and commitment fees on the unused portion of the available commitment vary depending on the Company’s credit ratings from Moody’s and S&P. At the Company’s current credit ratings, LIBOR Rate Loans and Alternate Base Rate Loans bear interest margins of 150 basis points and 50 basis points per annum, respectively, and commitment fees on the unused portion of the available commitment are 25 basis points per annum. During the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015,~~2017, the Company incurred commitment fees on the unused portion of the available commitments of $6$4 million, $8$5 million and $7$6 million, respectively. The Company had ~~$1.7~~$2.0 billion of unused commitments under the Credit Facility at December 31, ~~2017.~~

2019.

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

maintenance of certain financial ratios, including maintenance of a quarterly ratio of consolidated total debt to consolidated earnings, as defined, before interest expense, income taxes, depletion, depreciation, and

F-28

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

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

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

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

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

restrictions on the payment of cash dividends.

Senior notes. Interest on the Company’s senior notes is paid in arrears semi-annually. The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company’s 100 percent owned subsidiaries, subject to customary release provisions as described in Note ~~16.~~

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

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

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

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

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

In December 2016, the Company issued $600 million in aggregate principal amount of 4.375% senior notes due 2025 at par, for which it received net proceeds of approximately $592 million. The Company used the net proceeds from the offering to fund the satisfaction and discharge of its obligations under the indenture of the $600 million outstanding principal amount of its 6.5% unsecured senior notes due 2022 (the “6.5% Notes”) at a price equal to 103.25 percent of par. The early extinguishment price included the make-whole premium as determined in accordance with the indenture governing the 6.5% Notes. In December 2016, the Company also paid interest of approximately $20 million on the 6.5% Notes through January 16, 2017.

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

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

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

F-29

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

As a result of ~~the~~these transactions, ~~discussed above,~~ the Company recorded a loss on extinguishment of debt of $65 million for the year ended December 31, ~~2017 as follows:~~

2017.

Credit Facility

Senior Notes

April 2017

September 2017

(in millions)
Amendment

Tender Offer

Extinguishment

Total

Cash:

Tender premium
$
-

$
36

$
-

$
36

Make-whole premium

-


-


25


25

Prepaid interest

-


-


2


2

Total cash

-

36

27

63
Non-cash:

Unamortized original issue premium

-


(11)


(8)


(19)

Unamortized deferred loan costs

1


12


9


22

Total non-cash

1

1

1

3
Total loss on extinguishment of debt
$
1

$
37

$
28

$
66

At December 31, ~~2017,~~2019, the Company was in compliance with the covenants under all of its debt instruments.

Principal maturities of long-term debt.Principal maturities of long-term debt outstanding at December 31, ~~2017~~2019 were as follows:



(in millions)
2020	$	—
2021	—
2022	—
2023	—
2024	—
Thereafter	4,000
Total	$	4,000

Table of Contents

(in millions)

2018

$

-
2019

-
2020

-
2021

-
2022

322
Thereafter

2,400

Total

$

2,722

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015:~~2017:



(in millions)	Years Ended December 31,
(in millions)	2019			2018			2017
Cash payments for interest	$	207		$	118		$	139
Non-cash interest	6			5			6
Net changes in accruals	(9		)	34			4
Interest costs incurred	204			157			149
Less: capitalized interest	(19		)	(8		)	(3		)
Total interest expense	$	185		$	149		$	146

Years Ended December 31,
(in millions)

2017

2016

2015

Cash payments for interest

$
139

$
232

$
211
Non-cash interest

6

9


9
Net changes in accruals

4

(37)


-

Interest costs incurred

149

204

220
Less: capitalized interest

(3)

-


(5)

Total interest expense

$
146

$
204

$
215

F-30

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

Note ~~10.~~ 11. Commitments and contingencies

Severance agreements.The Company has entered into severance and change in control agreements with all of its officers. The current annual salaries for the Company’s officers covered under such agreements total ~~approximately $8~~$10 million.

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

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

Regulatory and environmental compliance. Regulatory liabilities relate to acquisitions where additional equipment is necessary to have facilities compliant with local, state and federal obligations. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs. At December 31, 2019 and 2018, the Company had regulatory and environmental liabilities of $10 million and $26 million, respectively, which are included in other current liabilities on the accompanying consolidated balance sheets. During the years ended December 31, 2019, 2018 and 2017, the Company recognized regulatory and environmental charges of $13 million, $23 million and $9 million, respectively, which are included in oil and natural gas production expensein the accompanying consolidated statements of operations.

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

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~~which includes throughput volume delivery commitments, fixed and variable power commitments, water commitment agreements, ~~throughput volume delivery~~sand commitment agreements and other commitments. The Company’s drilling rig commitments ~~power commitments, fixed asset commitments~~are considered leases under ASU 2016-02 and ~~maintenance commitments.~~are discussed in the “Leases” section below. The following table summarizes the Company’s commitments at December 31, ~~2017~~:

2019:

(in millions)

2018

$
33
2019

51
2020

33
2021

29
2022

26
Thereafter

84

Total

$
256

F-
(in millions) Volume Delivery Commitments (b) Power Commitments (a) Other Commitments Total
2020 $ 8
$ 14
$ 29
$ 51
2021 19
14
38
71
2022 19
14
5
38
2023 19
14
2
35
2024 19
14
2
35
Thereafter 54
44
5
103
Total $ 138
$ 114
$ 81
$ 333


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


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

At December 31,

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



	Oil (in MMBbl) (a)	Natural Gas (in MMcf)
2020	43	371
2021	51	7,267
2022	53	16,425
2023	51	16,425
2024	47	16,470
Thereafter	114	32,850
Total	359	89,808


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

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

~~Operating leases.~~

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



(in millions)	Classification	December 31, 2019
Assets
Operating lease right-of-use assets	Other property and equipment, net	$	15
Finance lease right-of-use assets	Other property and equipment, net	16
Total lease right-of-use assets (a)		$	31

Liabilities
Current:
Operating	Other current liabilities	$	8
Finance	Other current liabilities	7
Noncurrent:
Operating	Asset retirement obligations and other long-term liabilities	9
Finance	Asset retirement obligations and other long-term liabilities	10
Total lease liabilities (a)		$	34

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

As of December 31, 2019, the Company had additional operating leases ~~vehicles, equipment~~that have not yet commenced. Future undiscounted lease payments of $15 million and ~~office facilities~~estimated lease incentives of $5 million will be included in the determination of the right-of-use asset and lease liability upon lease commencement.

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



(in millions)	Classification	December 31, 2019
Operating lease cost	General and administrative	$	7
Finance lease cost	Depreciation, depletion, and amortization (a)	8
Total lease cost		$	15

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

The Company’s short-term leases are primarily composed of drilling rigs and certain field equipment. During the year ended December 31, 2019, the Company’s gross lease costs related to its short-term leases were $307 million, of which $207 million were capitalized as part of oil and natural gas properties. A portion of these costs was reimbursed to the Company by other working interest owners.

The following table summarizes supplemental cash flow information related to leases for the year ended December 31, 2019:



(in millions)	December 31, 2019
Cash paid for amounts included in measurement of lease liabilities:
Operating cash flows from operating leases	$	8
Financing cash flows from finance leases	$	7
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	3
Finance leases	$	9

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

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



	December 31, 2019
Weighted average remaining lease term (years):
Operating leases	3.2
Finance leases	2.8

Weighted average discount rate (a):
Operating leases	4.7	%
Finance leases	4.2	%

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

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



(in millions)	Operating Leases			Finance Leases
2020	$	8		$	7
2021	7			6
2022	2			4
2023	—			1
2024	—			—
Thereafter	2			—
Total lease payments	19			18
Less: interest	(2		)	(1		)
Present value of lease liabilities	$	17		$	17

As discussed in Note 2, the Company elected a transition method to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings. Per ASU 2016-02, an entity electing this transition method should provide the required disclosures under ~~non-cancellable operating leases. Lease~~Topic 840 for all periods that continue to be in accordance with Topic 840. As such, the Company included the future minimum lease commitments table below as of December 31, 2018. In addition, lease payments associated with these operating leases ~~for the year ended~~ ~~December 31, 2017 was approximately~~were $13 million and $10 million ~~and approximately $8 million~~ for ~~each of~~ the years ended December 31, ~~2016~~2018 and ~~2015~~,2017, respectively.

Future minimum lease commitments under non-cancellable ~~operating~~ leases at December 31, ~~2017~~2018 were as follows:



(in millions)	(in millions)

2018		$	10
2019	2019		8	$	14
2020	2020		7	12
2021	2021		5	10
2022	2022		-	3
2023				—
Thereafter	Thereafter		1	1
Total				$	40
	Total	$	31

F-32

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

Note ~~11.~~12. Income taxes

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

The Company’s income tax expense (benefit) attributable to income (loss) from operations consisted of the following for the years ended December 31, 2019, 2018 and 2017:



(in millions)	Years Ended December 31,
(in millions)	2019			2018			2017
Current:
U.S. federal	$	—		$	—		$	(6	)
U.S. state	—			(2		)	2
Total current income tax benefit	—			(2		)	(4		)
Deferred:
U.S. federal	(112		)	547			(94		)
U.S. state	(42		)	58			23
Total deferred income tax expense (benefit)	(154		)	605			(71		)
Total income tax expense (benefit)	$	(154	)	$	603		$	(75	)

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



(in millions)	Years Ended December 31,
(in millions)	2019			2018			2017
Income (loss) at U.S. federal statutory rate	$	(180	)	$	607		$	308
Non-deductible goodwill	64			—			—
Enactment date and measurement period adjustments from the TCJA	—			(7		)	(398		)
State income taxes and enacted tax law changes, net of federal tax effect	(13		)	52			17
Change in estimated effective statutory state income tax rate	(21		)	(8		)	—
Excess tax benefit due to stock-based compensation	—			(12		)	(6		)
Research and development credits, net of unrecognized tax benefits	(11		)	(41		)	—
Other	7			12			4
Income tax expense (benefit)	$	(154	)	$	603		$	(75	)

Effective tax rate	18		%	21		%	(9		)%

On December 22, 2017, the President signed into law the TCJA, which enacted significant changes to federal income tax laws, including a decrease in the federal corporate income tax rate from 35 percent to 21 percent, which was effective January 1, 2018. In accordance with the guidance stated in ASC 740, “Income Taxes,” the Company is required to account for the effects of an enacted tax law or rate change in the period of enactment, which is the date it is signed by the President. Set forth below is a discussion of certain provisions enacted by the TCJA and the Company’s assessment of the impact of such provisions on its consolidated results.

~~In accordance with~~ SAB 118, the Company has calculated its best estimate of the impact of the TCJA, including the federal statutory tax rate change noted above, in accordance with its understanding of the TCJA and guidance available as of the date of this filing and asrecorded, based on reasonable estimates, a ~~result has recorded $398~~ $398 million ~~as a~~ decrease to its income tax provision at December 31, ~~2017. The~~2017. This provisional amount related to the re-measurement of certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the ~~future, was $398~~ ~~million.~~

~~The TCJA also repealed the corporate alternative minimum tax (“AMT”) for tax years beginning after~~future. At December 31, ~~2017, and provides that existing AMT credit carryovers are refundable beginning with the~~ 2018, ~~tax year. The Company has approximately $10 million of AMT credit carryovers that are expected to be fully refunded by 2022.~~ At ~~December 31, 2017,~~ the Company ~~had current income tax receivables of approximately $5 million.~~

At ~~December 31, 2017~~, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2013 through 2017 remain subject to examination by the major tax jurisdictions.

~~The Company’s income tax expense (benefit) attributable to income (loss) from operations consisted~~completed its accounting for all of the ~~following for~~enactment-date tax effects of the ~~years ended~~ ~~December 31, 2017, 2016~~TCJA and ~~2015:~~

Years Ended December 31,
(in millions)

2017

2016

2015

Current:

U.S. federal

$
(6)

$
(12)

$
-

U.S. state and local

2

-

1

Total current income tax expense (benefit)

(4)

(12)

1
Deferred:

U.S. federal

(94)

(771)

40

U.S. state and local

23

(93)

(10)

Total deferred income tax expense (benefit)

(71)

(864)

30

Total income tax expense (benefit) attributable to income from operations

$
(75)

$
(876)

$
31

F-33

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

~~The reconciliation between the income tax expense (benefit) computed by multiplying pre-tax income (loss) from operations by the U.S. federal statutory rate and the reported amounts~~recognized an adjustment of $7 million, which is included as a component of income tax ~~expense (benefit) from operations is as follows:~~

expense.

Years Ended December 31,
(in millions)

2017

2016

2015

Income (loss) at U.S. federal statutory rate

$
308

$
(818)

$
34
Provisional change in deferred tax assets and liabilities

(398)

-

-
State income taxes, net of federal tax effect

17

(41)

3
Revisions of previous estimates

-

1

(1)
Change in estimated effective statutory state income tax

-

(21)

(9)
Excess tax benefit related to stock-based compensation

(6)

-

-
Nondeductible expense and other

4

3

4

Income tax expense (benefit)

$
(75)

$
(876)

$
31

Effective tax rate

(9)%

38%

32%

The Company monitors changes in enacted tax rates for the jurisdictions in which it operates. During 2019, the state of New Mexico enacted a tax law which, among other changes, amended the apportioned net operating loss (“NOL”) carryforwards for corporations. As a result of this law change, the Company recorded a deferred state tax benefit of $6 million for the year ended December 31, 2019. The Company monitors its state tax apportionment footprint and makes updates for changes in its projected activity, including changes in budgets and drilling ~~plans. During 2013,~~plans, and changes as a result of acquisitions or divestitures, including the ~~State of~~ New Mexico ~~passed legislation to phase~~Shelf divestiture in ~~a tax rate reduction over the next five years. In June of 2015, the State of Texas enacted legislation to reduce its rate.~~2019. Based upon the Company’s projected future activity for the states in which it conducts business, the timing for when it anticipates its deferred tax items to become taxable, ~~and~~the enacted tax rates at such time deferred items become

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

taxable and the New Mexico tax law change discussed above, the Company revised its estimated state tax rate for the year ended December 31, 2019. As a result, the Company recorded an income tax benefit of $21 million in its income tax provision for the year ended December 31, 2019. The Company revised its estimated state tax rate during 2018, primarily due to the impact of the RSP Acquisition. As a result, the Company recorded an income tax benefit of $8 million, net of federal tax benefit, in its income tax provision for the year ended December 31, 2018. The Company did not revise its estimated state rate and, as such, did not record an additional deferred state tax benefit ~~during 2017. The Company did revise its estimated state rate and recorded an additional deferred state tax benefit of approximately $21 million and $9 million during 2016~~ ~~and 2015, respectively.~~

~~The Company recorded a discrete income tax benefit of approximately $6 million~~ for the year ended December 31,, 2017.

The Company recorded an income tax benefit of $12 million and $6 million for the years ended December 31, 2018 and 2017, respectively, related to an excess tax ~~benefits~~benefit on stock-based awards, which isare recorded in the income tax provision pursuant to ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-based Payment Accounting,” (“ASU 2016-09”) adopted on January 1, ~~2017~~.

The Company’s 2017 effective tax rate decreased as compared to 2016 primarily due to the provisional $398 million income tax benefit recognized as a result of the re-measurement of the Company’s net deferred tax liability based on changes enacted by the TCJA. This benefit more than offset the $308 million income tax expense on income before income taxes during 2017 at the federal statutory rate.

The Company’s effective tax rate increased in 2016 as compared to 2015 primarily due to a shift from pre-tax earnings of $97 million in 2015 to a pre-tax loss of $2.3 billion in 2016, resulting in a less pronounced effect on the effective tax rate for each reconciling item. In particular, the reduction in the Company’s effective statutory state rate caused a 1 percent increase in 2016 as compared to a 9 percent reduction in 2015, partially offset by other reconciling and non-deductible items for a net rate increase of 5 percent over 2015.

At December 31, 2016, the Company had approximately $539 million of federal net operating losses (“NOLs”), of which $6 million was carried back to the 2014 tax year. During 2017, the Company projects it will utilize approximately $411 million of the remaining NOLs available of $533 million. At December 31, 2017, the Company had approximately $122 million of NOLs that will expire in 2036 but are allowable as a deduction against 100 percent of future taxable income since they were generated prior to the effective date of limitations imposed by the TCJA. Additionally, the Company has estimated an apportioned New Mexico NOL of approximately $111 million expiring in 2036.

2017.

F-34

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

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


				December 31,
(in millions)	(in millions)			2017			2016	December 31,

(in millions)								2019			2018
	*Deferred tax assets:*
	Stock-based compensation			$	18	$	39
	Derivative instruments				87		64
	Asset retirement obligation				33		48
	Net operating losses and credits				31		177
	Other				13		24
Stock-based compensation								$	24		$	26
Derivative instruments								23			—
Asset retirement obligation								31			41
Net operating losses and other carryforwards								590			525
Research and development and other credits								73			61
Other								22			17
Total deferred tax assets								763			670
Less: Valuation allowance								(4		)	(3		)
Net deferred tax assets								759			667
			Total deferred tax assets		182		352
*Deferred tax liabilities:*	*Deferred tax liabilities:*
Oil and natural gas properties, principally due to differences in basis and depreciation and the deduction of intangible drilling costs for tax purposes								(2,318		)	(2,270		)
Equity method investments								(83		)	—
Intangible assets - operating rights								(4		)	(4		)
Derivative instruments								—			(158		)
Other								(8		)	(43		)
Total deferred tax liabilities								(2,413		)	(2,475		)
Net deferred tax liabilities								$	(1,654	)	$	(1,808	)
	Oil and natural gas properties, principally due to differences in basis and
		depreciation and the deduction of intangible drilling costs for tax purposes			(852)		(1,095)
	Intangible assets				(5)		(9)
	Other				(12)		(14)
			Total deferred tax liability		(869)		(1,118)
			Net deferred tax liability	$	(687)	$	(766)

The Company had net deferred tax liabilities of approximately ~~$687 million~~$1.7 billion and ~~$766 million~~$1.8 billion as of December 31, ~~2017~~2019 and ~~2016,~~2018, respectively.

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

Pursuant to management’s assessment, the Company does not believe a cumulative ownership change ~~has~~had occurred as of December 31, ~~2017.~~2019. As such, Section 382 of the Internal Revenue Code of 1986, as amended, is not expected to limit the Company’s ability to utilize its NOL ~~carryforward as of~~carryforward.

At December 31, ~~2017.~~

2019, the Company had approximately $2.6 billion of federal NOLs, net of reduction for unrecognized tax benefits. At December 31, 2019, the Company had approximately $1.5 billion of NOLs that will begin to expire in the tax year 2034 but are allowable as a deduction against 100 percent of future taxable income since they were generated prior to the effective date of the limitations imposed by the TCJA. Additionally, the Company has estimated an apportioned New Mexico NOL of $749 million that will begin to expire in 2036.

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s NOLs and other deferred tax attributes will be utilized prior to their expiration. ~~At December 31, 2017, management~~Management considered all factors, including the expected reversal of deferred tax liabilities (including the impact of available ~~carryback and~~ carryforward periods), historical operating income tax planning strategies and projected future taxable income. Based on the results of the assessment, ~~management~~a valuation allowance of $4 million and $3 million was recorded at December 31, 2019 and 2018, respectively, related to charitable contribution carryforwards not anticipated to be utilized prior to expiration. Management determined that it is more likely than not that the Company will realize its remaining deferred tax assets.

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



(in millions)	December 31, 2019			December 31, 2018
Balance at beginning of year	$	72		$	—
Additions for tax positions acquired	—			26
Additions for prior period tax positions	—			20
Reductions for prior period tax positions	(1		)	—
Additions for current tax period positions	11			26
Balance at end of year	$	82		$	72

Total that, if recognized, would impact the effective income tax rate	$	74		$	63

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based upon the technical merits of the position. The Company had unrecognized tax benefits primarily related to research and development credits. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company’s deferred tax liability and will affect the Company’s effective tax rate in the period recognized. The timing as to when the Company will substantially resolve the uncertainties associated with the unrecognized tax benefit is uncertain. The Company does not expect that a change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

The Company has not recognized any interest or penalties relating to unrecognized tax benefits in its consolidated financial statements. Any interest or penalties would be recognized as a component of income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2014.

F-35

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~

Note ~~12.~~ 13.Major customers and derivative counterparties

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

The following purchasers individually accounted for 10 percent or more of the Company’s consolidated oil and natural gas revenues during the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015:~~

2017:

Years Ended December 31,

2017

2016

2015

Plains Marketing and Transportation, Inc.

21%

29%

11%
Holly Frontier Refining and Marketing, LLC

10%

16%

25%
Enterprise Crude Oil LLC

8%

7%

12%

~~At December 31, 2017,~~



	Years Ended December 31,
	2019		2018		2017
Plains Marketing and Transportation, Inc.	17	%	18	%	21	%
Enterprise Crude Oil LLC	10	%	(a)		(a)
Holly Frontier Refining and Marketing, LLC	(a)		(a)		10	%

(a) Purchaser did not account for 10% or more of total revenue for the ~~Company had receivables from Plains Marketing & Transportation Inc., Holly Frontier Refining and Marketing, LLC and Enterprise Crude Oil LLC of $~~72 ~~million, $~~36 ~~million and $~~30 ~~million, respectively, which are reflected in accounts receivable — oil and natural gasin the accompanying consolidated balance sheets.~~

period.

100

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Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 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.~~ Additionally, as a result of the Company’s Investment Grade Period election along with amendments to certain ISDA Agreements with the Company’s derivative counterparties, the Company’s derivatives are no longer secured. See

Note ~~9 for additional information regarding the Credit Facility.~~

~~Note 13.~~ 14.Related party transactions

The Company paid royalties on certain properties to a partnership in which a director of the Company is the general partner and owns a 3.5 percent partnership interest. These payments were reported in the Company’s consolidated statements of operations and totaled ~~approximately~~ $7 million, $4$8 million and $6$7 million for the years ended December 31, 2019, 2018 and 2017, ~~2016 and 2015,~~ respectively.

F-36

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

At December 31, ~~2017, 2016~~2019, the Company had ownership interests in entities that operate and ~~2015~~

manage various infrastructure assets and accounts for these investments using the equity method. The Company made payments of $40 million to these entities and received payments of $3 million from these entities during the year ended December 31, 2019.

Note ~~14.~~ 15.Earnings per share

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

The Company’s basic earnings (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 from operations and earnings attributable to common stockholders to the basic and diluted earnings used to determine the Company’s earnings per share amounts for the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015,~~2017, respectively, under the two-class method:

Years Ended December 31,

(in millions, except per share amounts)

2017

2016

2015

Net income (loss) as reported

$
956

$
(1,462)

$
66

Participating basic earnings (a)

(7)

-

(1)

Basic earnings attributable to common stockholders

949

(1,462)

65

Reallocation of participating earnings

-

-

-

Diluted earnings attributable to common stockholders

$
949

$
(1,462)

$
65

(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.



(in millions, except per share amounts)	Years Ended December 31,
(in millions, except per share amounts)	2019			2018			2017
Net income (loss) as reported	$	(705	)	$	2,286		$	956
Participating basic earnings (a)	(1		)	(17		)	(7		)
Basic earnings attributable to common stockholders	(706		)	2,269			949
Reallocation of participating earnings	—			—			—
Diluted earnings attributable to common stockholders	$	(706	)	$	2,269		$	949

(a)

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

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015:~~

Years Ended December 31,
(in thousands)

2017

2016

2015

Weighted average common shares outstanding:




Basic

147,320

134,755

119,926

Dilutive common stock options

3

-

25

Dilutive performance units

633

-

422

Diluted

147,956

134,755

120,373

2017:

F-37

~~Concho Resources Inc.~~

~~Notes to Consolidated Financial Statements~~

~~December 31, 2017, 2016 and 2015~~



(in thousands)	Years Ended December 31,
(in thousands)	2019	2018	2017
Weighted average common shares outstanding:
Basic	198,984	170,925	147,320
Dilutive common stock options	—	—	3
Dilutive performance units	—	324	633
Diluted	198,984	171,249	147,956

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



(in thousands)	Years Ended December 31,
	2019	2018	2017
Number of antidilutive common shares:
Antidilutive performance units	431	108	81

101

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Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2019, 2018 and 2017

Note 16. Stockholders’ equity

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 $1.5 billion of the Company’s common stock. A portion of the proceeds from the New Mexico Shelf divestiture was used to initiate the share repurchase program. As of December 31, 2019, the Company had repurchased and retired 3,300,370 shares under the program at an aggregate cost of $250 million. The Company’s share repurchase program may be modified, suspended or terminated at any time by the Company’s board of directors. The Company is not obligated to acquire any specific number of shares.

Common stock dividends. The Company paid dividends of $100 million, or $0.50 per share, during the year ended December 31, 2019. 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 could limit the payment of dividends.

Years Ended December 31,
(in thousands)

2017

2016

2015

Number of antidilutive common shares:




Antidilutive performance units

81

-

-

Note ~~15.~~ 17.Other current liabilities

The following table provides the components of the Company’s other current liabilities at December 31, ~~2017~~2019 and ~~2016:~~

2018:


				December 31,
(in millions)	(in millions)			2017		2016	December 31,
(in millions)							2019		2018
(in millions)
Accrued production costs							$	175	$	135
Payroll related matters							37		49
Accrued interest							60		70
Settlements due on derivatives							38		—
Asset retirement obligations							9		11
Other							44		55
Other current liabilities							$	363	$	320

*Other current liabilities:*
	Accrued production costs		$	72	$	63
	Payroll related matters			40		35
	Accrued interest			36		32
	Settlements due on derivatives			25		-
	Asset retirement obligations			12		10
	Other			31		12
		Other current liabilities	$	216	$	152

F-38

102

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

Note ~~16.~~ 18. Subsidiary guarantors

At December 31, ~~2017,~~ 2019, certain of the Company’s 100 percent owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be released in certain customary circumstances including (i) in connection with any sale, exchange or other disposition, whether by merger, consolidation or otherwise, of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Company to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee.

See Note 910 for a summary of the Company’s senior notes. In accordance with practices accepted by the SEC, the Company has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. In addition, ~~two~~certain 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~~These entities isare 100 percent owned subsidiaries and are referred to as “Subsidiary Non-Guarantors” in the tables below. An additional entity did not guarantee the Company’s senior notes at December 31, 2017. This entity was a VIE that was formed to effectuate a tax-free exchange of assets. During 2018, the Reverse Exchange 1031 was completed and all assets and liabilities attributable to the ~~other~~VIE were conveyed to the Company. This entity ~~is a 100 percent owned subsidiary that~~did not guarantee the Company’s senior notes until the conveyance was ~~recently acquired. These entities are referred to as “Subsidiary Non-Guarantors” in~~completed. See Note 5 for additional information regarding the ~~tables below.~~

completion of the Reverse 1031 Exchange.

The following condensed consolidating balance sheets at December 31, ~~2017~~2019 and ~~2016~~,2018, condensed consolidating statements of operations and condensed consolidating statements of cash flows for the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~,2017, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company.

F-39

103

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

Condensed Consolidating Balance Sheet
December 31, 2017

Parent

Subsidiary

Subsidiary

Consolidating

(in millions)


Issuer


Guarantors

Non-Guarantors


Entries


Total

ASSETS








Accounts receivable - related parties

$
8,836

$
(669)

$
-

$
(8,167)

$
-
Other current assets


6

576

10

-

592
Oil and natural gas properties, net


-

12,192

615

-

12,807
Property and equipment, net


-

234

-

-

234
Investment in subsidiaries


3,202

-

-

(3,202)

-
Other long-term assets


23

76

-

-

99

Total assets

$
12,067

$
12,409

$
625

$
(11,369)

$
13,732









LIABILITIES AND EQUITY







Accounts payable - related parties

$
(669)

$
8,223

$
613

$
(8,167)

$
-
Other current liabilities


341

821

3

-

1,165
Long-term debt


2,691

-

-

-

2,691
Other long-term liabilities


789

166

6

-

961
Equity


8,915

3,199

3

(3,202)

8,915

Total liabilities and equity

$
12,067

$
12,409

$
625

$
(11,369)

$
13,732

Condensed Consolidating 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

550

-

562
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

244

-

255

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


113

640

-

753
Long-term debt


2,741

-

-

2,741
Other long-term liabilities


862

140

-

1,002
Equity


7,623

1,989

(1,989)

7,623

Total liabilities and equity

$
11,003

$
11,760

$
(10,644)

$
12,119

F-40



Condensed Consolidating Balance Sheet December 31, 2019
(in millions)	Parent Issuer		Subsidiary Guarantors		Subsidiary Non-Guarantor		Consolidating Entries			Total
ASSETS
Accounts receivable - related parties	$	17,429	$	—	$	—	$	(17,429	)	$	—
Other current assets	10		1,045		—		—			1,055
Oil and natural gas properties, net	—		20,874		16		—			20,890
Property and equipment, net	—		437		—		—			437
Investment in subsidiaries	5,635		—		—		(5,635		)	—
Goodwill	—		1,917		—		—			1,917
Other long-term assets	22		411		—		—			433
Total assets	$	23,096	$	24,684	$	16	$	(23,064	)	$	24,732

LIABILITIES AND EQUITY
Accounts payable - related parties	$	—	$	17,413	$	16	$	(17,429	)	$	—
Other current liabilities	211		971		—		—			1,182
Long-term debt	3,955		—		—		—			3,955
Other long-term liabilities	1,148		665		—		—			1,813
Equity	17,782		5,635		—		(5,635		)	17,782
Total liabilities and equity	$	23,096	$	24,684	$	16	$	(23,064	)	$	24,732



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

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

104

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

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

Parent

Subsidiary

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors

Non-Guarantors

Entries


Total
Total operating revenues

$
-

$
2,566

$
20

$
-

$
2,586
Total operating costs and expenses


(129)

(1,366)

(17)

-

(1,512)

Income (loss) from operations


(129)

1,200

3

-

1,074
Interest expense


(145)

(1)

-

-

(146)
Loss on extinguishment of debt


(66)

-

-

-

(66)
Other, net


1,221

19

-

(1,221)

19

Income before income taxes


881

1,218

3

(1,221)

881
Income tax benefit


75

-

-

-

75

Net income

$
956

$
1,218

$
3

$
(1,221)

$
956

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

Parent

Subsidiary

Consolidating

(in millions)

Issuer

Guarantors

Entries

Total



Total operating revenues

$
-

$
1,635

$
-

$
1,635
Total operating costs and expenses


(370)

(3,334)

-

(3,704)

Loss from operations


(370)

(1,699)

-

(2,069)
Interest expense


(202)

(2)

-

(204)
Loss on extinguishment of debt


(56)

-

-

(56)
Other, net


(1,710)

(9)

1,710

(9)

Loss before income taxes


(2,338)

(1,710)

1,710

(2,338)
Income tax benefit


876

-

-

876

Net loss

$
(1,462)

$
(1,710)

$
1,710

$
(1,462)

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2015

Parent

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors

Entries


Total



Total operating revenues

$
-

$
1,804

$
-

$
1,804
Total operating costs and expenses


697

(2,174)

-

(1,477)

Income (loss) from operations


697

(370)

-

327
Interest expense


(213)

(2)

-

(215)
Other, net


(387)

(15)

387

(15)

Income (loss) before income taxes


97

(387)

387

97
Income tax expense


(31)

-

-

(31)

Net income (loss)

$
66

$
(387)

$
387

$
66

F-41



Condensed Consolidating Statement of Operations For the Year Ended December 31, 2019
(in millions)	Parent Issuer			Subsidiary Guarantors			Subsidiary Non-Guarantor		Consolidating Entries			Total
Total operating revenues	$	—		$	4,591		$	1	$	—		$	4,592
Total operating costs and expenses	(898		)	(4,681		)	—		—			(5,579		)
Income (loss) from operations	(898		)	(90		)	1		—			(987		)
Interest expense	(185		)	—			—		—			(185		)
Other, net	224			313			—		(224		)	313
Income (loss) before income taxes	(859		)	223			1		(224		)	(859		)
Income tax benefit	154			—			—		—			154
Net income (loss)	$	(705	)	$	223		$	1	$	(224	)	$	(705	)



Condensed Consolidating Statement of Operations For the Year Ended December 31, 2018
(in millions)	Parent Issuer			Subsidiary Guarantors			Subsidiary Non-Guarantor			Consolidating Entries			Total
Total operating revenues	$	—		$	4,146		$	5		$	—		$	4,151
Total operating costs and expenses	829			(2,047		)	(3		)	—			(1,221		)
Income from operations	829			2,099			2			—			2,930
Interest expense	(149		)	—			—			—			(149		)
Other, net	2,209			108			—			(2,209		)	108
Income before income taxes	2,889			2,207			2			(2,209		)	2,889
Income tax expense	(603		)	—			—			—			(603		)
Net income	$	2,286		$	2,207		$	2		$	(2,209	)	$	2,286



Condensed Consolidating Statement of Operations For the Year Ended December 31, 2017
(in millions)	Parent Issuer			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Entries			Total
Total operating revenues	$	—		$	2,566		$	20		$	—		$	2,586
Total operating costs and expenses	(129		)	(1,369		)	(17		)	—			(1,515		)
Income (loss) from operations	(129		)	1,197			3			—			1,071
Interest expense	(145		)	(1		)	—			—			(146		)
Loss on extinguishment of debt	(66		)	—			—			—			(66		)
Other, net	1,221			22			—			(1,221		)	22
Income before income taxes	881			1,218			3			(1,221		)	881
Income tax benefit	75			—			—			—			75
Net income	$	956		$	1,218		$	3		$	(1,221	)	$	956

105

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

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

Parent

Subsidiary

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors

Non-Guarantors

Entries

Total



Net cash flows provided by operating activities

$
145

$
1,549

$
1

$
-

$
1,695
Net cash flows used in investing activities


-

(1,105)

(614)

-

(1,719)
Net cash flows provided by (used in)

financing activities


(145)

(497)

613

-

(29)

Net decrease in cash and cash equivalents


-

(53)

-

-

(53)

Cash and cash equivalents at beginning

of period


-

53

-

-

53

Cash and cash equivalents at end of period

$
-

$
-

$
-

$
-

$
-

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

Parent

Subsidiary

Consolidating

(in millions)


Issuer

Guarantors

Entries


Total



Net cash flows provided by (used in) operating activities

$
(665)

$
2,049

$
-

$
1,384
Net cash flows used in investing activities

-

(2,225)

-

(2,225)
Net cash flows provided by financing activities

665

-

-

665

Net decrease in cash and cash equivalents

-

(176)

-

(176)

Cash and cash equivalents at beginning of period

-

229

-

229

Cash and cash equivalents at end of period

$
-

$
53

$
-

$
53

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2015

Parent

Subsidiary

Consolidating

(in millions)

Issuer

Guarantors

Entries


Total

Net cash flows provided by (used in) operating activities

$
(1,394)

$
2,924

$
-

$
1,530
Net cash flows used in investing activities

-

(2,602)

-


(2,602)
Net cash flows provided by (used in) financing activities

1,394

(93)

-


1,301

Net increase in cash and cash equivalents

-

229

-

229

Cash and cash equivalents at beginning of period

-

-

-

-

Cash and cash equivalents at end of period

$
-

$
229

$
-

$
229



Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2019
(in millions)	Parent Issuer			Subsidiary Guarantors			Subsidiary Non-Guarantor		Consolidating Entries		Total
Net cash flows provided by operating activities	$	607		$	2,229		$	—	$	—	$	2,836
Net cash flows used in investing activities	—			(1,993		)	—		—		(1,993		)
Net cash flows used in financing activities	(607		)	(166		)	—		—		(773		)
Net change in cash and cash equivalents	—			70			—		—		70
Cash and cash equivalents at beginning of period	—			—			—		—		—
Cash and cash equivalents at end of period	$	—		$	70		$	—	$	—	$	70

F-42



Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2018
(in millions)	Parent Issuer			Subsidiary Guarantors			Subsidiary Non-Guarantor		Consolidating Entries		Total
Net cash flows provided by operating activities	$	338		$	2,220		$	—	$	—	$	2,558
Net cash flows used in investing activities	—			(2,216		)	—		—		(2,216		)
Net cash flows used in financing activities	(338		)	(4		)	—		—		(342		)
Net change in cash and cash equivalents	—			—			—		—		—
Cash and cash equivalents at beginning of period	—			—			—		—		—
Cash and cash equivalents at end of period	$	—		$	—		$	—	$	—	$	—



Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2017
(in millions)	Parent Issuer			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Entries		Total
Net cash flows provided by operating activities	$	145		$	1,549		$	1		$	—	$	1,695
Net cash flows used in investing activities	—			(1,105		)	(614		)	—		(1,719		)
Net cash flows provided by (used in) financing activities	(145		)	(497		)	613			—		(29		)
Net change 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	$	—		$	—		$	—		$	—	$	—

106

Table of Contents

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

Note ~~17.~~ 19. Subsequent events

~~Southern Delaware Basin divestitures.~~ ~~In January 2018,~~

Dividends. On February 18, 2020, the ~~Company closed on two asset sales transactions~~Company’s board of ~~certain non-core assets in Reeves and Ward Counties with combined preliminary proceeds~~directors declared a cash dividend of ~~approximately $280 million, subject to customary post-closing adjustments. As of December 31, 2017, the Company received cash deposits totaling approximately $29 million~~$0.20 per share for the ~~asset sales, which was included in the~~first quarter of 2020. The total cash ~~flows from investing activities in its consolidated statement~~dividend, including the cash dividend on unvested restricted stock awards, of ~~cash flows. The assets divested included proved and unproved oil and natural gas properties~~$39 million is expected to be paid on ~~approximately 20,000 net acres. This completed the Reverse 1031 Exchange discussed in Note 4.~~

~~February 2018 nonmonetary transaction.~~ In February 2018, the Company closed on a trade where it received approximately 21,000 net acres, primarily located in the Midland Basin, with current production of 5 MBoepd in exchange for approximately 34,000 net acres, primarily comprised of approximately 32,000 net acres in the northern Delaware Basin, with current production of 3 MBoepd.

March 27, 2020.

New commodity derivative contracts.After December 31, ~~2017,~~2019, 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:



	2020
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total		2021			2022
Oil Price Swaps – WTI: (a)
Volume (MBbl)	—		—		—		—		—		365			—
Price per Bbl	$	—	$	—	$	—	$	—	$	—	$	55.24		$	—
Oil Basis Swaps: (b)
Volume (MBbl)	—		1,092		309		61		1,462		1,460			—
Price per Bbl	$	—	$	1.11	$	1.05	$	1.00	$	1.09	$	1.23		$	—
Natural Gas Price Swaps - Henry Hub: (c)
Volume (BBtu)	—		—		—		—		—		29,200			36,500
Price per MMBtu	$	—	$	—	$	—	$	—	$	—	$	2.34		$	2.38
Natural Gas Basis Swaps - Henry Hub/El Paso Permian: (d)
Volume (BBtu)	—		—		—		—		—		14,600			29,200
Price per MMBtu	$	—	$	—	$	—	$	—	$	—	$	(1.08	)	$	(0.72	)
Natural Gas Basis Swaps - Henry Hub/WAHA: (e)
Volume (BBtu)	—		—		—		—		—		7,300			7,300
Price per MMBtu	$	—	$	—	$	—	$	—	$	—	$	(1.30	)	$	(0.85	)


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

F-43

107

Concho Resources Inc.

Unaudited Supplementary Data

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

Capitalized costs

December 31,

(in millions)

2017

2016

Oil and natural gas properties:

Proved

$
18,565

$
16,620

Unproved

2,702

1,856

Less: accumulated depletion

(8,460)

(7,390)

Net capitalized costs for oil and natural gas properties

$
12,807
(a)
$
11,086

(a)
Approximately $135 million of the balance at December 31, 2017 relates to assets held for sale. See Note 17 for additional information.

(in millions) December 31,
2019 2018
Oil and natural gas properties:
Proved $ 22,915
$ 24,992
Unproved 5,870
6,714
Less: accumulated depletion (7,895 ) (9,701 )
Net capitalized costs for oil and natural gas properties $ 20,890
$ 22,005

Costs incurred for oil and natural gas producing activities

Years Ended December 31,
(in millions)

2017

2016

2015

Property acquisition costs:




Proved

$
303

$
982

$
57

Unproved


905

1,154

206
Exploration


1,021

701

1,123
Development


653

449

709

Total costs incurred for oil and natural gas properties

$
2,882

$
3,286

$
2,095

F-44



(in millions)	Years Ended December 31,
(in millions)	2019		2018		2017
Property acquisition costs:
Proved	$	8	$	4,136	$	303
Unproved	50		3,617		905
Exploration	1,637		1,588		1,021
Development	1,358		1,050		653
Total costs incurred for oil and natural gas properties	$	3,053	$	10,391	$	2,882

108

Concho Resources Inc.

Unaudited Supplementary Data

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

~~Results of operations for oil and natural gas producing activities~~

The following table provides results of operations for the Company’s oil and natural gas producing activities and excludes amounts incurred from the Company’s non-oil and gas producing activities for the years ended December 31, 2017, 2016 and 2015:

Years Ended December 31,
(in millions)

2017

2016

2015

Oil and natural gas producing activities:

Operating revenues:

Oil sales

$
2,092

$
1,350

$
1,540

Natural gas sales

494

285

264

Total operating revenues

2,586

1,635

1,804

Operating costs and expenses:

Oil and natural gas production

408

320

390

Production and ad valorem taxes

199

131

151

Exploration and abandonments

59

77

59

Depreciation, depletion and amortization

1,146

1,167

1,223

Accretion of discount on asset retirement obligation

8

7

8

Impairments of long-lived assets

-

1,525

61

General and administrative

244

226

231

(Gain) loss on derivatives

126

369

(700)

(Gain) loss on disposition of assets, net

(23)

(118)

54

Total operating costs and expenses

2,167

3,704

1,477

Income (loss) before income taxes

419

(2,069)

327

Income tax (expense) benefit at statutory rate

(154)

759

(122)

Net income (loss)

$
265

$
(1,310)

$
205

F-45

~~Concho Resources Inc.~~

~~Unaudited Supplementary Data~~

~~December 31, 2017, 2016 and 2015~~

Reserve Quantity Information

The following information represents estimates of the Company’s proved ~~reserves as of December 31, 2017.~~reserves. The pricing that was used for estimates of the Company’s reserves as of December 31, ~~2017~~2019 was based on the SEC pricing of ~~$47.79~~$52.19 per Bbl West Texas Intermediate posted oil price and ~~$2.98~~$2.58 per MMBtu Henry Hub spot natural gas price. ~~See table below.~~

Subject to limited exceptions, proved undeveloped reserves may only be recognized if they relate to wells scheduled to be drilled within five years of the date of their initial recognition. This rule limited, and may continue to limit, the Company’s potential to record additional proved undeveloped ~~reserves as it pursues its drilling program, particularly as it develops its significant acreage in the Permian Basin of southeast New Mexico and west Texas.~~reserves. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. All of the Company’s recorded proved undeveloped reserves are scheduled to be drilled within five years of the date of their initial recognition.

The Company’s proved oil and natural gas reserves are all located in the United States, primarily in the Permian Basin of ~~southeast~~West Texas and Southeast New ~~Mexico and west Texas.~~Mexico. All of the estimates of the proved reserves at December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~2017 are based on reports prepared by Cawley, Gillespie & Associates, Inc. and Netherland, Sewell & Associates, Inc., independent petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

The following table summarizes the prices utilized in the reserve estimates for ~~2017, 2016~~2019, 2018 and ~~2015.~~2017. Commodity prices utilized for the reserve estimates prior to adjustments for location, grade and quality are as follows:

December 31,

2017

2016

2015

Prices utilized in the reserve estimates before adjustments:

Oil per Bbl

$
47.79

$
39.25

$
46.79

Natural gas per MMBtu

$
2.98

$
2.48

$
2.59



	December 31,
	2019		2018		2017
Prices utilized in the reserve estimates before adjustments:
Oil per Bbl	$	52.19	$	62.04	$	47.79
Natural gas per MMBtu	$	2.58	$	3.10	$	2.98

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

F-46

109

Concho Resources Inc.

Unaudited Supplementary Data

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

The following table provides a rollforward of the total proved reserves for the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015,~~2017, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year.

2017

2016

2015

Oil and
Condensate
(MMBbls)

Natural
Gas
(Bcf)

Total
(MMBoe)

Oil and
Condensate
(MMBbls)

Natural
Gas
(Bcf)

Total
(MMBoe)

Oil and
Condensate
(MMBbls)

Natural
Gas
(Bcf)

Total
(MMBoe)

Total Proved Reserves:

Balance, January 1

428

1,752

720

368

1,534

623

370

1,601

637

Purchases of minerals-in-place

22
��
72

34

41

109

59

7

28

12

Sales of minerals-in-place

(2)

(9)

(4)

(6)

(15)

(8)

(1)

(3)

(2)

Extensions and discoveries

115

351

174

84

247

125

97

359

157

Revisions of previous estimates

(20)

38

(14)

(25)

4

(24)

(71)

(344)

(129)

Production

(43)

(161)

(70)

(34)

(127)

(55)

(34)

(107)

(52)

Balance, December 31

500

2,043

840

428

1,752

720

368

1,534

623

Proved Developed Reserves:

January 1

267

1,190

466

204

927

358

211

993

377

December 31

336

1,512

588

267

1,190

466

204

927

358

Proved Undeveloped Reserves:

January 1

161

561

254

164

607

265

159

608

260

December 31

164

531

252

161

561

254

164

607

265

2019 2018 2017

Oil and
Condensate
(MMBbls)

Natural
Gas
(Bcf)

Total
(MMBoe)

Oil and
Condensate
(MMBbls)

Natural
Gas
(Bcf)

Total
(MMBoe)

Oil and
Condensate
(MMBbls)

Natural
Gas
(Bcf)

Total
(MMBoe)
Total Proved Reserves:
Balance, January 1 750
2,624
1,187
500
2,043
840
428
1,752
720
Purchases of minerals-in-place 6
19
9
233
449
308
22
72
34
Sales of minerals-in-place (57 ) (288 ) (105 ) (8 ) (54 ) (17 ) (2 ) (9 ) (4 )
Extensions and discoveries 121
331
177
151
452
226
115
351
174
Revisions of previous estimates (125 ) (121 ) (145 ) (65 ) (58 ) (74 ) (20 ) 38
(14 )
Production (76 ) (267 ) (121 ) (61 ) (208 ) (96 ) (43 ) (161 ) (70 )
Balance, December 31 619
2,298
1,002
750
2,624
1,187
500
2,043
840

Proved Developed Reserves:
January 1 500
1,941
824
336
1,512
588
267
1,190
466
December 31 442
1,818
745
500
1,941
824
336
1,512
588

Proved Undeveloped Reserves:
January 1 250
683
363
164
531
252
161
561
254
December 31 177
480
257
250
683
363
164
531
252

For the year ended December 31, 2019:

Extensions and discoveries. Extensions and discoveries of approximately 177 MMBoe were primarily the result of the Company’s horizontal drilling programs in its operating areas. Proved developed reserves increased approximately 106 MMBoe due to the Company’s drilling activity in 2019, and based upon this activity, the Company added approximately 71 MMBoe of new proved undeveloped reserves.

Purchases and sales of minerals-in-place. The Company’s purchases of minerals-in-place were primarily the result of certain acquisitions and nonmonetary transactions during 2019. The Company’s sales of 105 MMBoe of minerals-in-place were the result of various divestitures and nonmonetary transactions during 2019, primarily the New Mexico Shelf divestiture. See Note 5 for additional information.

Revisions of previous estimates. Revisions of previous estimates were composed of (i) 28 MMBoe of negative revisions primarily due to the reclassification of proved undeveloped reserves to unproved as they were no longer expected to be developed within five years of the date of their initial recognition, (ii) 82 MMBoe of net negative performance and other revisions and (iii) 35 MMBoe of negative price revisions. The Company’s proved reserves at December 31, 2019 were determined using the SEC prices of $52.19 per Bbl of oil for WTI and $2.58 per MMBtu of natural gas for Henry Hub spot, as compared to corresponding prices of $62.04 per Bbl of oil and $3.10 per MMBtu of natural gas at December 31, 2018. Negative performance revisions were primarily the result of the Company’s recent capital programs that included projects testing tighter well spacing. The Company has modified its development approach to prioritize wider spacing between wells in order to maximize well performance and program economics.

For the year ended December 31, 2018:

Extensions and discoveries. Extensions and discoveries of approximately 226 MMBoe were primarily the result of the Company’s horizontal drilling programs in the Company’s operating areas. Proved developed reserves increased approximately 87 MMBoe due to the Company’s drilling activity in 2018. Based upon this activity, approximately 139 MMBoe of new proved undeveloped locations were added.

Purchases and sales of minerals-in-place. The Company’s purchases of minerals-in-place were primarily the result of the RSP Acquisition in July 2018 which added approximately 275 MMBoe. The remainder of the purchases of minerals-in-place was primarily the result of certain acquisitions and nonmonetary transactions during 2018, which added approximately 25 MMBoe in the Midland

110

Concho Resources Inc.

Unaudited Supplementary Data

December 31, 2019, 2018 and 2017

Basin and 8 MMBoe in the Delaware Basin. The Company’s sales of minerals-in-place were primarily the result of various divestitures and nonmonetary transactions during 2018.

Revisions of previous estimates. Revisions of previous estimates were primarily composed of (i) 77 MMBoe of negative revisions primarily due to proved undeveloped reserves reclassified to unproved, (ii) 15 MMBoe of net negative performance and other revisions and (iii) 18 MMBoe of positive price revisions. As the Company transitioned its development program to large-scale projects and evaluated and analyzed its producing oil and natural gas properties and drilling prospects, certain properties were no longer expected to be developed within five years of the date of their initial recognition and were removed from the Company’s current drilling plans. This included certain properties that were identified to have a lower liquids content and certain non-operated properties that the Company reclassified due to the uncertainty regarding the timing of development. Net negative performance and other revisions primarily related to 27 MMBoe of downward revisions to certain proved developed producing properties in the Yeso field, partially offset by other positive performance revisions. Positive price revisions were the result of an increase in the oil and natural gas prices utilized in the Company’s reserve estimates at December 31, 2018 as compared to December 31, 2017.

For the year ended December 31, 2017:

Purchases and sales of ~~minerals-in-place~~. minerals-in-place.The Company’s purchases of minerals-in-place ~~are~~were composed of approximately 11 MMBoe from the July 2017 Midland Basin acquisition, 8 MMBoe from the January 2017 ~~Northern~~ Delaware Basin acquisition and 15 MMBoe from various other acquisitions throughout the year. The Company’s sales of minerals-in-place are composed of approximately 4 MMBoe from various divestitures throughout the year.

Extensions and ~~discoveries~~. discoveries.Extensions and discoveries of approximately 174 MMBoe ~~are~~were primarily the result of the Company’s ~~continued success from its~~ extension and infill horizontal drilling programs in its ~~core~~ operating areas. Proved developed reserves increased approximately 82 MMBoe due to the Company’s exploratory drilling activity in 2017. Based upon this activity, approximately 92 MMBoe of new proved undeveloped locations were added.

Revisions of previous ~~estimates~~. estimates.Revisions of previous estimates ~~are~~were composed of (i) 61 MMBoe of negative revisions due to proved undeveloped reserves reclassified to unproved reserves because they are no longer expected to be developed within five years of the date of their initial recognition as required by SEC rules due to a shift in the Company’s capital program to generally focus more on large-scale development projects in certain areas, (ii) 29 MMBoe of positive price revisions and (iii) 18 MMBoe of positive technical and performance revisions. Our proved reserves at December 31, 2017 were determined using the SEC pricing of $47.79 per Bbl WTI posted oil price and $2.98 per MMBtu Henry Hub spot natural gas price, as compared to corresponding prices of $39.25 per Bbl of oil and $2.48 per MMBtu of natural gas at December 31, 2016.

~~For the year ended December 31, 2016:~~

~~Purchases and sales of minerals-in-place.~~The Company’s purchases of minerals-in-place are composed of approximately 42 MMBoe from the October 2016 Reliance Acquisition, 15 MMBoe from the March 2016 Southern Delaware Basin acquisition and 2 MMBoe from various other acquisitions throughout the year. The Company’s sales of minerals-in-place are composed of approximately 8 MMBoe from various divestitures throughout the year.

~~Extensions and discoveries~~. Extensions and discoveries of approximately 125 MMBoe are primarily the result of the Company’s continued success from its extension and infill horizontal drilling programs in its core operating areas. Proved developed reserves increased approximately 61 MMBoe due to the Company’s exploratory drilling activity last year. Based upon this activity, approximately 64 MMBoe of new proved undeveloped locations were added, of which the majority are one offset location from an existing producing well.

F-47

~~Concho Resources Inc.~~

~~Unaudited Supplementary Data~~

~~December 31, 2017, 2016 and 2015~~

~~Revisions of previous estimates~~. Revisions of previous estimates are comprised of (i) 57 MMBoe of negative revisions due to proved undeveloped reserves reclassified to unproved reserves because they are no longer expected to be developed within five years of the date of their initial recognition and (ii) 30 MMBoe of negative price revisions, partially offset by 63 MMBoe of net positive revisions related to lower lease operating expense estimates. The 57 MMBoe of proved undeveloped reserves in item (i) above are outside the five-year development window primarily due to results the Company has obtained during 2016 related to increased testing and implementation of new technologies that allows for drilling extended length laterals. The results are generally highly successful and provide sufficient data that substantiates drilling extended length laterals is generally a more efficient process than shorter lateral drilling to recover reserves. The results also generally confirm that the drilling of longer laterals is feasible on a large scale and substantially decreases the risks associated with a drilling program more focused on extended length laterals. Consequently, the Company shifted its capital program to focus on drilling more extended length laterals.

~~For the year ended December 31, 2015:~~

~~Purchases and sales of minerals-in-place.~~ ~~The Company’s purchases of minerals-in-place are composed of approximately 12 MMBoe from various acquisitions throughout the year and 2 MMBoe from various divestitures throughout the year.~~

~~Extensions and discoveries.~~ Extensions and discoveries of approximately 157 MMBoe are primarily the result of the Company’s continued success from its extension and infill horizontal drilling programs in its core operating areas. There were approximately 55 MMBoe of proved developed reserves that were directly added through the Company’s drilling activity last year. Based upon this activity, approximately 102 MMBoe of new proved undeveloped locations were added, of which the vast majority are one offset location from an existing producing well.

~~Revisions of previous estimates.~~ Revisions of previous estimates are comprised of (i) 112 MMBoe of negative price revisions, (ii) 11 MMBoe of negative revisions due to proved undeveloped reserves reclassified to unproved reserves because they are no longer expected to be developed within the five years of the date of their initial recognition required by SEC rules and (iii) 6 MMBoe net negative revision resulting from technical and performance evaluations.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

F-48

111

Concho Resources Inc.

Unaudited Supplementary Data

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

The following table provides the standardized measure of discounted future net cash flows at December 31, 2019, 2018 and 2017:



(in millions)	December 31,
(in millions)	2019			2018			2017
Oil and gas producing activities:
Future cash inflows	$	36,001		$	56,621		$	29,761
Future production costs	(13,519		)	(16,511		)	(9,612		)
Future development and abandonment costs (a)	(2,672		)	(3,731		)	(2,636		)
Future income tax expense	(2,570		)	(5,694		)	(2,565		)
Future net cash flows	17,240			30,685			14,948
10% annual discount factor	(7,657		)	(15,130		)	(7,470		)
Standardized measure of discounted future net cash flows	$	9,583		$	15,555		$	7,478

(a) Includes $249 million, $329 million and $256 million of undiscounted asset retirement cash outflow estimated at December 31, 2019, 2018 and 2017, ~~2016 and 2015:~~

respectively, using current estimates of future abandonment costs less salvage values.

December 31,
(in millions)

2017

2016

2015

Oil and gas producing activities:

Future cash inflows

$
29,761

$
20,674

$
20,133

Future production costs

(9,612)

(7,945)

(7,667)

Future development and abandonment costs (a)

(2,636)

(2,458)

(3,357)

Future income tax expense

(2,565)

(1,382)

(1,119)

Future net cash flows

14,948

8,889

7,990

10% annual discount factor

(7,470)

(4,699)

(4,251)

Standardized measure of discounted future net cash flows

$
7,478

$
4,190

$
3,739

(a)
Includes $256 million, $231 million and $197 million of undiscounted asset retirement cash outflow estimated at December 31, 2017, 2016 and 2015, respectively, using current estimates of future abandonment costs less salvage values. See Note 5 for corresponding information regarding the Company’s discounted asset retirement obligations.

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table provides a rollforward of the standardized measure of discounted future net cash flows for the years ended December 31, ~~2017, 2016~~2019, 2018 and ~~2015:~~

Years Ended December 31,
(in millions)

2017

2016

2015

Oil and natural gas producing activities:

Purchases of minerals-in-place

$
304

$
497

$
74

Sales of minerals-in-place

(20)

(62)

(5)

Extensions and discoveries

2,014

1,116

1,022

Development costs incurred during the period

619

278

464

Net changes in prices and production costs

1,830

(935)

(7,893)

Oil and natural gas sales, net of production costs

(1,979)

(1,184)

(1,263)

Changes in future development costs

84

591

988

Revisions of previous quantity estimates

(154)

(189)

(1,125)

Accretion of discount

470

405

1,065

Changes in production rates, timing and other

470

62

(449)

Change in present value of future net revenues

3,638

579

(7,122)

Net change in present value of future income tax expense (benefit)

(350)

(128)

2,838

3,288

451

(4,284)
Balance, beginning of year

4,190

3,739

8,023
Balance, end of year

$
7,478

$
4,190

$
3,739

2017:

F-49



	Year Ended December 31,
(in millions)	2019			2018			2017
Oil and natural gas producing activities:
Purchases of minerals-in-place	$	103		$	4,555		$	304
Sales of minerals-in-place	(899		)	(176		)	(20		)
Extensions and discoveries	2,241			3,562			2,014
Development costs incurred during the period	1,086			783			619
Net changes in prices and production costs	(6,789		)	2,926			1,830
Oil and natural gas sales, net of production costs	(3,412		)	(3,201		)	(1,979		)
Changes in future development costs	203			304			84
Revisions of previous quantity estimates	(1,606		)	(1,113		)	(154		)
Accretion of discount	1,635			1,001			470
Changes in production rates, timing and other	74			827			470
Change in present value of future net revenues	(7,364		)	9,468			3,638
Net change in present value of future income tax benefit	1,392			(1,391		)	(350		)
	(5,972		)	8,077			3,288
Balance, beginning of year	15,555			7,478			4,190
Balance, end of year	$	9,583		$	15,555		$	7,478

112

Concho Resources Inc.

Unaudited Supplementary Data

December 31, ~~2017, 2016~~2019, 2018 and ~~2015~~

2017

Selected Quarterly Financial Results

The following table provides selected quarterly financial results for the years ended December 31, ~~2017~~2019 and ~~2016:~~

2018:

Quarter
(in millions, except per share data)

First

Second

Third

Fourth

Year ended December 31, 2017:

Total operating revenues

$
612

$
567

$
627

$
780

Operating costs and expenses (excluding gains (losses)

on derivatives and gains on disposition of assets, net)

(491)

(507)

(511)

(555)

Gains (losses) on derivatives

286

209

(206)

(415)

Gains on disposition of assets, net

654

-

13

11

Income (loss) from operations

$
1,061

$
269

$
(77)

$
(179)

Income tax (expense) benefit

$
(371)

$
(93)

$
66

$
473

Net income (loss)

$
650

$
152

$
(113)

$
267

Earnings per common share - Basic

$
4.39

$
1.02

$
(0.77)

$
1.80

Earnings per common share - Diluted

$
4.37

$
1.02

$
(0.77)

$
1.79

Year ended December 31, 2016:

Total operating revenues

$
284

$
396

$
430

$
525

Operating costs and expenses (excluding gains (losses)

on derivatives)

(1,918)

(467)

(469)

(481)

Gains (losses) on derivatives

81

(298)

41

(193)

Income (loss) from operations

$
(1,553)

$
(369)

$
2

$
(149)

Net loss

$
(1,020)

$
(266)

$
(51)

$
(125)

Earnings per common share - Basic

$
(7.95)

$
(2.04)

$
(0.38)

$
(0.86)

Earnings per common share - Diluted

$
(7.95)

$
(2.04)

$
(0.38)

$
(0.86)

F-50



	Quarter
(in millions, except per share data)	First			Second			Third			Fourth
Year ended December 31, 2019:
Total operating revenues	$	1,104		$	1,127		$	1,115		$	1,246
Operating costs and expenses (excluding gains (losses) on derivatives and gains on disposition of assets, net) (a)	(892		)	(1,748		)	(993		)	(1,221		)
Gains (losses) on derivatives	(1,059		)	217			397			(450		)
Gains (losses) on disposition of assets, net	1			(1		)	303			(133		)
Income (loss) from operations	$	(846	)	$	(405	)	$	822		$	(558	)

Income tax (expense) benefit	$	194		$	53		$	(222	)	$	129

Net income (loss)	$	(695	)	$	(97	)	$	558		$	(471	)

Earnings per common share - Basic	$	(3.49	)	$	(0.48	)	$	2.78		$	(2.38	)

Earnings per common share - Diluted	$	(3.49	)	$	(0.48	)	$	2.78		$	(2.38	)


Year ended December 31, 2018:
Total operating revenues	$	947		$	945		$	1,192		$	1,067
Operating costs and expenses (excluding gains (losses) on derivatives and gains on disposition of assets, net)	(620		)	(610		)	(787		)	(836		)
Gains (losses) on derivatives	(35		)	(133		)	(625		)	1,625
Gains (losses) on disposition of assets, net	723			1			(5		)	81
Income (loss) from operations	$	1,015		$	203		$	(225	)	$	1,937

Income tax (expense) benefit	$	(254	)	$	(40	)	$	69		$	(378	)

Net income (loss)	$	835		$	137		$	(199	)	$	1,513

Earnings per common share - Basic	$	5.60		$	0.92		$	(1.05	)	$	7.56

Earnings per common share - Diluted	$	5.58		$	0.92		$	(1.05	)	$	7.55

(a)

Third and fourth quarters of 2019 include $81 million and $201 million of goodwill impairment charges, respectively. Refer to Note 2 for additional information related to impairments of goodwill. In addition, second and third quarters of 2019 include $868 million and $20 million of impairments of long-lived assets, respectively. Refer to Note 8 for additional information related to impairments of long-lived assets.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

We had no changes in, and no disagreements with, our accountants on accounting and financial disclosure.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this 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 December 31, 2019 at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting. The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

As of December 31, 2019, management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria established in “Internal Control - Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that the Company maintained effective internal control over financial reporting at December 31, 2019.

Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this annual report on Form 10-K, has issued its report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2019. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2019, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Concho Resources Inc.

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Concho Resources Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2019, and our report dated February 19, 2020 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

Definition and limitations of internal control over financial reporting

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

February 19, 2020

Item 9B. Other Information

None.

PART III

Item 10.Directors, Executive Officers and Corporate Governance

Code of Ethics. Our board of directors has adopted a financial code of ethics applicable to our Chief Executive Officer, President, Chief Financial Officer, Chief Accounting Officer and other senior financial officers, and a code of business conduct and ethics applicable to our directors, officers and employees, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE (the “Codes”). The Codes can be found on our website located at www.concho.com. We intend to disclose future amendments to certain provisions of the Codes, and waivers of the Codes granted to executive officers and directors, on our website within four business days following the date of the amendment or waiver.

Item 11.Executive Compensation

Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Equity compensation plans. At December 31, 2019, a total of 15,000,000 shares of common stock were authorized for issuance under our equity compensation plan. In the table below, we describe certain information about these shares and the equity compensation plan which provides for their authorization and issuance. Included in column (1) are (i) unvested performance units at the maximum potential payout percentage and (ii) performance units relating to the performance period that ended on December 31, 2019 at the actual payout percentage of 38 percent. You can find descriptions of our stock incentive plan under Note 7 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”



Plan category	(1) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(2) Weighted average exercise price of outstanding options			(3) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (1))
Equity compensation plan approved by the security holders (a)	1,013,942	$	—	(c)	4,961,182
Equity compensation plan not approved by the security holders (b)	—	$	—		—
Total	1,013,942				4,961,182


(a) 2019 Stock Incentive Plan. See Note 7 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”
(b) None.
(c) Performance unit awards do not have an exercise price and, therefore, have been excluded from the weighted average exercise price calculation in column (2).

The remaining information required by Item 12 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2019.

Item 13.Certain Relationships and Related Transactions, and Director Independence

Item 14.Principal Accountant Fees and Services

PART IV


Item 15.	Exhibits, Financial Statement Schedules


(a)	Listing of Financial Statements

Financial Statements

The following consolidated financial statements are included in “Item 8. Financial Statements and Supplementary Data”:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets at December 31, 2019 and 2018

Consolidated Statements of Operations for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

Notes to Consolidated Financial Statements

Unaudited Supplementary Data


(b)	Exhibits

The exhibits to this report required to be filed pursuant to Item 15(b) are listed below.


(c)	Financial Statement Schedules

No financial statement schedules are required to be filed as part of this report or they are inapplicable.

Exhibits



Exhibit Number		Description
2.1		Agreement and Plan of Merger among Concho Resources Inc., RSP Permian, Inc. and Green Merger Sub Inc., dated as of March 27, 2018 (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on March 28, 2018, and incorporated herein by reference).

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

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

4.1		Specimen Common Stock Certificate (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		Senior Indenture, dated September 18, 2009, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on September 22, 2009, and incorporated herein by reference).

4.3		Tenth Supplemental Indenture, dated December 28, 2016, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on December 28, 2016, and incorporated herein by reference).

4.4		Eleventh Supplemental Indenture, dated January 25, 2017, among Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.4 to the Company’s Registration Statement on Form S-3 on June 14, 2018, and incorporated herein by reference).

4.5		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 4.1 to the Company’s Current Report on Form 8-K on September 26, 2017, and incorporated herein by reference).

4.6		Thirteenth 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 4.2 to the Company’s Current Report on Form 8-K on September 26, 2017, and incorporated herein by reference).

4.7		Fourteenth Supplemental Indenture, dated July 2, 2018, among Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on July 2, 2018, and incorporated herein by reference).




4.8		Fifteenth Supplemental Indenture, dated July 2, 2018, among 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 July 2, 2018, and incorporated herein by reference).

4.9		Sixteenth Supplemental Indenture, dated August 14, 2018, among Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on August 15, 2018, and incorporated herein by reference).

4.10	(a)	Description of Securities

10.1	**	Form of Performance Unit Award Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 4, 2013, and incorporated herein by reference).

10.2	**	Form of Performance Unit Award Agreement, dated January 2, 2019 (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).

10.3	**	Form of Performance Unit Award Agreement, dated January 2, 2020 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 6, 2020, and incorporated herein by reference).

10.4	**	Performance Unit Award Agreement, dated January 2, 2018, by and between Concho Resources Inc. and E. Joseph Wright (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 4, 2018, and incorporated herein by reference).

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

10.6	**	Form of Nonstatutory Stock Option Agreement (filed as Exhibit 10.16 to the Company’s Annual Report on Form 10-K on March 28, 2008, and incorporated herein by reference).

10.7	**	Form of Restricted Stock Agreement (for officers) (filed as Exhibit 10.1 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).

10.8	**	Form of Restricted Stock Agreement (for non-employee directors) (filed as Exhibit 10.18 to the Company’s Annual Report on Form 10-K on March 28, 2008, and incorporated herein by reference).

10.9	**	Restricted Stock Agreement, dated January 2, 2018, between Concho Resources Inc. and E. Joseph Wright (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on January 4, 2018, and incorporated herein by reference).

10.10	**	Form of Restricted Stock Agreement (for officers) (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).

10.11	**	Form of Succession Restricted Stock Agreement, dated January 2, 2019, between Concho Resources Inc. and each of Messrs. Harper and Giraud (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).

10.12	**	Form of Indemnification Agreement, dated January 2, 2019, between Concho Resources Inc. and each of the officers and directors thereof (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).

10.13	**	Form of Succession 3-Year Performance Unit Award Agreement, dated January 2, 2019, between Concho Resources Inc. and each of Messrs. Harper and Giraud (filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).

10.14	**	Form of Succession 5-Year Performance Unit Award Agreement, dated January 2, 2019, between Concho Resources Inc. and each of Messrs. Harper and Giraud (filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).

10.15	**	Second Amended and Restated Credit Agreement, dated as of May 9, 2014, among Concho Resources Inc., the lenders party thereto, JPMorgan Chase Bank, N.A., as administrative agent, and the co-syndication agents and co-documentation agents named therein (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q on May 12, 2014, and incorporated herein by reference).

10.16	**	First Amendment to Second Amended and Restated Credit Agreement, dated as of April 8, 2015, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 9, 2015, and incorporated herein by reference).

10.17	**	Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 12, 2017, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q on August 3, 2017, and incorporated herein by reference).

10.18		Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 29, 2019, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q on August 1, 2019, and incorporated herein by reference).



10.19	**	Executive Severance Plan, dated January 1, 2019, by and between Concho Resources Inc. and each of the officers thereof (filed as Exhibit 10.7 to the Company’s Current Report on Form 8-K on January 4, 2019, and incorporated herein by reference).

21.1	(a)	Subsidiaries of Concho Resources Inc.

23.1	(a)	Consent of Grant Thornton LLP.

23.2	(a)	Consent of Netherland, Sewell & Associates, Inc.

23.3	(a)	Consent of Cawley, Gillespie & Associates, Inc.

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

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

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

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

99.1	(a)	Netherland, Sewell & Associates, Inc. Reserve Report, dated January 23, 2020.

99.2	(a)	Cawley, Gillespie & Associates, Inc. Reserve Report, dated January 27, 2020.

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

101.SCH	(a)	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 Annual Report on Form 10-K for the year ended December 31, 2019, formatted in Inline XBRL and included within the Exhibit 101 attachments.

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


Item 16.	Form 10-K Summary

None.

SIGNATURES



CONCHO RESOURCES INC.

Date:	February 19, 2020	By	/s/ Timothy A. Leach

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



Signature	Title	Date

/s/ TIMOTHY A. LEACH	Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)	February 19, 2020
Timothy A. Leach

/s/ BRENDA R. SCHROER	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)	February 19, 2020
Brenda R. Schroer

/s/ JACOB P. GOBAR	Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 19, 2020
Jacob P. Gobar

/s/ STEVEN L. BEAL	Director	February 19, 2020
Steven L. Beal

/s/ TUCKER S. BRIDWELL	Director	February 19, 2020
Tucker S. Bridwell

/s/ WILLIAM H. EASTER III	Director	February 19, 2020
William H. Easter III

/s/ STEVEN D. GRAY	Director	February 19, 2020
Steven D. Gray

/s/ SUSAN J. HELMS	Director	February 19, 2020
Susan J. Helms

/s/ GARY A. MERRIMAN	Director	February 19, 2020
Gary A. Merriman

/s/ MARK B. PUCKETT	Director	February 19, 2020
Mark B. Puckett

/s/ JOHN P. SURMA	Director	February 19, 2020
John P. Surma

/s/ E. JOSEPH WRIGHT	Director	February 19, 2020
E. Joseph Wright

123



Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter:	$	17,883,517,337

Number of shares of the registrant’s common stock outstanding as of February 16, 2018:		149,067,852



Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter:	$	20,479,372,863

Number of shares of the registrant's common stock outstanding as of February 14, 2020	196,705,121


		Years Ended December 31,
			2017	2016	2015

Gross wells			311	249	361
Net wells			197	170	228

Percent of gross wells drilled horizontally			100%	100%	86%

Percent of gross wells:
	Producers		61%	56%	74%
	Unsuccessful		1%	-	1%
	Awaiting completion at year-end		38%	44%	25%
			100%	100%	100%


		December 31, 2017

			Estimated			Total	Total	2017 Average
			Proved			Gross	Net	Daily
			Reserves		% Proved	Acreage	Acreage	Production
Core Operating Areas			(MMBoe)	% Oil	Developed	(in thousands)	(in thousands)	(MBoe per Day)

Northern Delaware Basin			295	50%	68%	373	259	90
Southern Delaware Basin			127	72%	62%	146	94	27
Midland Basin			266	66%	67%	265	154	45
New Mexico Shelf			152	56%	87%	121	78	31
	Total		840	60%	70%	905	585	193



Operating Areas	December 31, 2019
Operating Areas	Estimated Proved Reserves (MMBoe)	% Oil		% Proved Developed		Total Gross Acreage (in thousands)	Total Net Acreage (in thousands)	2019 Average Daily Production (MBoe per Day)
Delaware Basin	556	61	%	76	%	524	352	217
Midland Basin	446	63	%	73	%	285	197	114
Total	1,002	62	%	74	%	809	549	331



	Drilling In-Progress		Pending Completion
	Gross	Net	Gross	Net

Development and exploratory wells	35	22	85	49


				Gross Productive Wells			Net Productive Wells
					Natural			Natural
				Oil	Gas	Total	Oil	Gas	Total

*December 31, 2017*
	Core Operating Areas:
		Northern Delaware Basin		1,282	439	1,721	726	213	939
		Southern Delaware Basin		319	26	345	195	17	212
		Midland Basin		2,747	15	2,762	1,675	6	1,681
		New Mexico Shelf		3,200	121	3,321	2,548	44	2,592
	Other			-	3	3	-	-	-
			Total	7,548	604	8,152	5,144	280	5,424

*December 31, 2016*
	Core Operating Areas:
		Northern Delaware Basin		1,164	454	1,618	662	212	874
		Southern Delaware Basin		270	27	297	163	17	180
		Midland Basin		2,577	15	2,592	1,298	5	1,303
		New Mexico Shelf		3,222	126	3,348	2,560	33	2,593
	Other			-	3	3	-	-	-
			Total	7,233	625	7,858	4,683	267	4,950

*December 31, 2015*
	Core Operating Areas:
		Northern Delaware Basin		1,141	460	1,601	651	217	868
		Southern Delaware Basin		222	53	275	138	29	167
		Midland Basin		2,476	24	2,500	1,173	8	1,181
		New Mexico Shelf		3,143	114	3,257	2,531	42	2,573
	Other			-	3	3	-	0	0
			Total	6,982	654	7,636	4,493	296	4,789



		Oil	Natural Gas	Total
		(MMBbl)	(Bcf)	(MMBoe)
Core Operating Areas:
	Northern Delaware Basin	149	878	295
	Southern Delaware Basin	92	214	128
	Midland Basin	175	546	266
	New Mexico Shelf	84	404	151
Other		-	1	-
	Total	500	2,043	840


				Purchases of	Sales of	Revisions of
			Extensions and	Minerals-in-	Minerals-in-	Previous
		Production	Discoveries	Place	Place	Estimates

Core Operating Areas:
	Northern Delaware Basin	(33)	63	15	-	16
	Southern Delaware Basin	(10)	29	4	-	(4)
	Midland Basin	(16)	77	14	(4)	2
	New Mexico Shelf	(11)	5	1	-	(28)
	Total	(70)	174	34	(4)	(14)



	Production		Extensions and Discoveries	Purchases of Minerals-in- Place	Sales of Minerals-in- Place		Revisions of Previous Estimates
Operating Areas:
Delaware Basin	(79	)	111	6	(102	)	(54	)
Midland Basin	(42	)	66	3	(3	)	(91	)
Total	(121	)	177	9	(105	)	(145	)


		Future		Future		Future		Future
Years Ended		Production		Cash		Production		Development		Future Net
December 31, (a)		(MMBoe)		Inflows (b)		Costs		Costs		Cash Flows

2018		9	$	346	$	(51)	$	(709)	$	(415)
2019		20		796		(120)		(623)		53
2020		26		987		(158)		(611)		219
2021		25		918		(153)		(228)		537
2022		20		728		(131)		(85)		512
Thereafter		152		5,656		(1,403)		-		4,253
	Total	252	$	9,431	$	(2,016)	$	(2,256)	$	5,159


(a)	Beginning in 2018 and thereafter, the production and cash flows represent the drilling results from the respective year plus the incremental effects from the results of proved undeveloped drilling from previous years.

(b)	Computation is based on SEC pricing of (i) $47.79 per Bbl WTI posted oil price and (ii) $2.98 per MMBtu Henry Hub spot natural gas price, adjusted for location and quality by property.


		Developed Acres (a)		Undeveloped Acres (b)		Total Acres
(in thousands)		Gross	Net	Gross	Net	Gross	Net

Core Operating Areas:
	Northern Delaware Basin	194	131	179	128	373	259
	Southern Delaware Basin	72	56	74	38	146	94
	Midland Basin	187	110	78	44	265	154
	New Mexico Shelf	69	45	52	33	121	78
	Total	522	342	383	243	905	585

			2018		2019		2020		Thereafter
(in thousands)			Gross	Net	Gross	Net	Gross	Net	Gross	Net

Core Operating Areas:
	Northern Delaware Basin		3	3	3	3	2	1	9	9
	Southern Delaware Basin		15	8	9	5	10	1	-	-
	Midland Basin (a)		1	-	-	1	1	-	-	-
	New Mexico Shelf		2	-	1	-	2	1	1	1
		Total	21	11	13	9	15	3	10	10


(a)		Expiring net acres are greater than gross acres in our Midland Basin core area in 2019 as certain leases contain undivided interests and have multiple net acreage expiration dates within the same tract of land. Expirations of net acres are shown in the year they occur, while the expirations of gross acres are shown in the final year of net acre expiration.
(a)


		Price Per Share
		High		Low

2016:
	First Quarter	$	107.00	$	69.94
	Second Quarter	$	130.03	$	95.87
	Third Quarter	$	137.83	$	114.33
	Fourth Quarter	$	147.55	$	123.88

2017:
	First Quarter	$	145.60	$	122.65
	Second Quarter	$	136.93	$	112.73
	Third Quarter	$	134.03	$	106.73
	Fourth Quarter	$	155.05	$	128.86

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

October 1, 2017 - October 31, 2017		103	$	133.24	-
November 1, 2017 - November 30, 2017		35	$	138.40	-
December 1, 2017 - December 31, 2017		360	$	143.64	-


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


				Years Ended December 31,
(in millions, except per share amounts)				2017 (a)		2016 (a) (b)		2015 (a)		2014		2013

Statement of operations data:
	Total operating revenues		$	2,586	$	1,635	$	1,804	$	2,660	$	2,320
	Total operating costs and expenses			(1,512)		(3,704)		(1,477)		(1,580)		(1,704)
Income (loss) from operations			$	1,074	$	(2,069)	$	327	$	1,080	$	616
Income (loss) from continuing operations, net of tax			$	956	$	(1,462)	$	66	$	538	$	239
Income from discontinued operations, net of tax				-		-		-		-		12
Net income (loss) attributable to common shareholders			$	956	$	(1,462)	$	66	$	538	$	251
Basic earnings per share:
	Income (loss) from continuing operations		$	6.44	$	(10.85)	$	0.54	$	4.89	$	2.28
	Income from discontinued operations, net of tax			-		-		-		-		0.11
		Net income (loss) attributable to common shareholders	$	6.44	$	(10.85)	$	0.54	$	4.89	$	2.39
Diluted earnings per share:
	Income (loss) from continuing operations		$	6.41	$	(10.85)	$	0.54	$	4.88	$	2.28
	Income from discontinued operations, net of tax			-		-		-		-		0.11
		Net income (loss) attributable to common shareholders	$	6.41	$	(10.85)	$	0.54	$	4.88	$	2.39

Other financial data:
	Net cash provided by operations		$	1,695	$	1,384	$	1,530	$	1,746	$	1,330
	Net cash used in investing activities		$	1,719	$	2,225	$	2,602	$	2,618	$	1,864
	Net cash provided by (used in) financing activities		$	(29)	$	665	$	1,301	$	872	$	532
	EBITDAX (c)		$	1,893	$	1,633	$	1,713	$	2,033	$	1,686




				December 31,
(in millions)				2017 (a)		2016 (a) (b)		2015 (a)		2014		2013

Balance sheet data:
	Cash and cash equivalents		$	-	$	53	$	229	$	-	$	-
	Property and equipment, net			13,041		11,302		10,976		10,206		8,946
	Total assets			13,732		12,119		12,642		11,752		9,508
	Long-term debt, including current maturities			2,691		2,741		3,332		3,469		3,577
	Stockholders’ equity			8,915		7,623		6,943		5,281		3,758


				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total

Oil Price Swaps: (a)
	*2018:*
		Volume (Bbl)		915,000		1,213,000		1,013,000		674,000		3,815,000
		Price per Bbl	$	63.64	$	63.48	$	63.34	$	63.11	$	63.42
	*2019:*
		Volume (Bbl)		876,000		748,000		636,000		552,000		2,812,000
		Price per Bbl	$	58.14	$	58.12	$	58.10	$	58.08	$	58.11
	*2020:*
		Volume (Bbl)		1,001,000		1,001,000		1,012,000		1,012,000		4,026,000
		Price per Bbl	$	54.80	$	54.80	$	54.80	$	54.80	$	54.80
Oil Basis Swaps: (b)
	*2018:*
		Volume (Bbl)		615,000		637,000		399,000		306,000		1,957,000
		Price per Bbl	$	0.13	$	0.06	$	(0.07)	$	(0.10)	$	0.03
	*2019:*
		Volume (Bbl)		180,000		182,000		184,000		-		546,000
		Price per Bbl	$	(0.27)	$	(0.27)	$	(0.27)	$	-	$	(0.27)
	*2020:*
		Volume (Bbl)		2,184,000		2,184,000		2,208,000		2,208,000		8,784,000
		Price per Bbl	$	(0.09)	$	(0.09)	$	(0.09)	$	(0.09)	$	(0.09)
Natural Gas Price Swaps: (c)
	*2018:*
		Volume (MMBtu)		1,277,000		878,000		921,000		274,000		3,350,000
		Price per MMBtu	$	3.08	$	3.08	$	3.08	$	3.08	$	3.08


(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.


			Year Ended December 31,
			2017	2016	2015

*Production:*
	South Basin Wolfcamp Bone Spring:
		Oil (MMBbl)	12	11	10
		Natural gas (Bcf)	75	56	37
		Total (MMBoe)	25	20	16
	Midland Basin Spraberry-Wolfcamp:
		Oil (MMBbl)	8	6	(a)
		Natural gas (Bcf)	26	20	(a)
		Total (MMBoe)	12	9	(a)
	Yeso:
		Oil (MMBbl)	7	7	7
		Natural gas (Bcf)	28	27	27
		Total (MMBoe)	12	12	12


(a) Represented less than 15% of the Company's total proved reserves for the year indicated.



		Years Ended December 31,
(dollars in millions)		2016		2015

Interest expense		$	204	$	215
Capitalized interest			-		5
	Interest expense, excluding impact of capitalized interest	$	204	$	220

Weighted average interest rate - credit facility			-		2.4%
Weighted average interest rate - senior notes			5.9%		5.9%
Total weighted average interest rate			5.8%		5.8%

Weighted average credit facility balance		$	-	$	195
Weighted average senior notes balance			3,182		3,350
	Total weighted average debt balance	$	3,182	$	3,545


		Payments Due by Period
				Less than		1 - 3		3 - 5		More than
(in millions)		Total		1 year		years		years		5 years

Long-term debt (a)		$	2,722	$	-	$	-	$	322	$	2,400
Cash interest expense on debt (b)			1,797		150		229		222		1,196
Derivative liabilities (c)			379		277		102		-		-
Asset retirement obligations (d)			141		12		13		3		113
Employment agreements with officers (e)			8		8		-		-		-
Purchase obligations (f)			256		33		84		55		84
Operating lease obligations (g)			31		10		15		5		1
	Total contractual obligations	$	5,334	$	490	$	443	$	607	$	3,794


			2017				2016
			Increase of		Decrease of		Increase of		Decrease of
			$5.00 per Bbl and		$5.00 per Bbl and		$5.00 per Bbl and		$5.00 per Bbl and
(in millions)			$0.50 per MMBtu		$0.50 per MMBtu		$0.50 per MMBtu		$0.50 per MMBtu
				��
Gain (loss):
	Oil derivatives		$	(290)	$	290	$	(216)	$	216
	Natural gas derivatives			(37)		37		(33)		33
		Total	$	(327)	$	327	$	(249)	$	249


				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			331		220
		Joint operations and other			212		238
	Inventory				14		16
	Derivative instruments				-		4
	Prepaid costs and other				35		31
			Total current assets		592		562
Property and equipment:
	Oil and natural gas properties, successful efforts method				21,267		18,476
	Accumulated depletion and depreciation				(8,460)		(7,390)
		Total oil and natural gas properties, net			12,807		11,086
	Other property and equipment, net				234		216
		Total property and equipment, net			13,041		11,302
Funds held in escrow					-		43
Deferred loan costs, net					13		11
Intangible assets, net					26		24
Other assets					60		177
	Total assets			$	13,732	$	12,119
Liabilities and Stockholders’ Equity
Current liabilities:
	Accounts payable - trade			$	43	$	28
	Bank overdrafts				116		-
	Revenue payable				183		132
	Accrued drilling costs				330		359
	Derivative instruments				277		82
	Other current liabilities				216		152
			Total current liabilities		1,165		753
Long-term debt					2,691		2,741
Deferred income taxes					687		766
Noncurrent derivative instruments					102		96
Asset retirement obligations and other long-term liabilities					172		140
Commitments and contingencies (Note 10)
Stockholders’ equity:
	Common stock, $0.001 par value; 300,000,000 authorized; 149,324,849 and 146,488,685
		shares issued at December 31, 2017 and 2016, respectively			-		-
	Additional paid-in capital				7,142		6,783
	Retained earnings				1,840		884
	Treasury stock, at cost; 598,049 and 429,708 shares at December 31, 2017 and 2016,
		respectively			(67)		(44)
			Total stockholders’ equity		8,915		7,623
	Total liabilities and stockholders’ equity			$	13,732	$	12,119

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


			Common Stock Issued			Additional							Total
			Common Stock 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 JANUARY 1, 2015			113,265	$	-	$	3,028	$	2,280	260	$	(27)	$	5,281
	Net income		-		-		-		66	-		-		66
	Issuance of common stock		15,755		-		1,536		-	-		-		1,536
	Stock options exercised		5		-		-		-	-		-		-
	Grants of restricted stock		452		-		-		-	-		-		-
	Cancellation of restricted stock		(33)		-		-		-	-		-		-
	Stock-based compensation		-		-		63		-	-		-		63
	Excess tax benefits related to stock-based
		compensation	-		-		2		-	-		-		2
	Purchase of treasury stock		-		-		-		-	46		(5)		(5)
BALANCE AT DECEMBER 31, 2015			129,444		-		4,629		2,346	306		(32)		6,943
	Net loss		-		-		-		(1,462)	-		-		(1,462)
	Issuance of common stock		10,350		-		1,327		-	-		-		1,327
	Common stock issued in business combinations		6,134		-		768		-	-		-		768
	Stock options exercised		23		-		1		-	-		-		1
	Grants of restricted stock		451		-		-		-	-		-		-
	Performance unit share conversion		180		-		-		-	-		-		-
	Cancellation of restricted stock		(93)		-		-		-	-		-		-
	Stock-based compensation		-		-		59		-	-		-		59
	Tax deficiency related to stock-based													��
		compensation	-		-		(1)		-	-		-		(1)
	Purchase of treasury stock		-		-		-		-	124		(12)		(12)
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		-		-		-		956	-		-		956
	Common stock issued in business combinations		2,177		-		291		-	-		-		291
	Stock options exercised		20		-		-		-	-		-		-
	Grants of restricted stock		490		-		-		-	-		-		-
	Performance unit share conversion		249		-		-		-	-		-		-
	Cancellation of restricted stock		(100)		-		-		-	-		-		-
	Stock-based compensation		-		-		60		-	-		-		60
	Purchase of treasury stock		-		-		-		-	168		(23)		(23)
BALANCE AT DECEMBER 31, 2017			149,325	$	-	$	7,142	$	1,840	598	$	(67)	$	8,915

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



(in millions)
(in millions)
Total purchase price	$	7,549

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

Total purchase price plus liabilities assumed	$	10,100

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


(in millions)

Fair value of net assets:
	Proved oil and natural gas properties		$	730
	Unproved oil and natural gas properties			972
	Other assets			34
		Total assets acquired		1,736
	Current liabilities, including current portion of asset retirement obligations			(8)
	Asset retirement obligations assumed			(12)
		Fair value of net assets acquired	$	1,716

Fair value of consideration paid for net assets:
	Cash consideration		$	1,176
	Non-cash consideration, including equity			540
	Total consideration paid for net assets		$	1,716


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

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


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

Restricted stock:

	Outstanding at December 31, 2016		1,157,270		$	115.29
		Shares granted	490,300		$	123.16
		Shares cancelled / forfeited	(100,199)		$	113.56
		Lapse of restrictions	(398,125)		$	117.91
	Outstanding at December 31, 2017		1,149,246		$	118.02


			Number of		Grant Date
			Units		Fair Value

Performance units:

	Outstanding at December 31, 2016		331,526	$	136.68
		Units granted (a)	108,398	$	183.48
		Units forfeited	(43,333)	$	140.00
		Units vested (b)	(148,944)	$	156.86
	Outstanding at December 31, 2017		247,647	$	146.10


(a)	Reflects the amount of performance units granted. The actual payout of shares will be between zero and 300 percent of the performance units granted depending on the Company’s performance at the end of the performance period.

(b)	On December 31, 2017, the performance period ended for these performance units. Each unit converted into three shares representing 446,832 shares of common stock issued on January 2, 2018.


		December 31, 2017				December 31, 2016
		Carrying		Fair		Carrying		Fair
(in millions)		Value		Value		Value		Value

Assets:
	Derivative instruments	$	-	$	-	$	4	$	4

Liabilities:
	Derivative instruments	$	379	$	379	$	178	$	178
	Credit facility	$	322	$	322	$	-	$	-
	$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	$	624	$	592	$	599
	$1,000 million 3.75% senior notes due 2027 (a)	$	987	$	1,012	$	-	$	-
	$800 million 4.875% senior notes due 2047 (a)	$	789	$	874	$	-	$	-


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


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

	Assets
		Current:
			Commodity derivatives		$	-	$	13	$	-	$	13	$	(13)	$	-
		Noncurrent:
			Commodity derivatives			-		1		-		1		(1)		-

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

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