UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☑

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

For the quarterly period ended September 30, 2017

2019

or

o

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

For the transition period fromto

a

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)

Code)

        (432) 683-7443


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


Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, par value $0.001 per shareCXONew York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑þ No o  

¨

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

¨

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

þ

Accelerated filer o 

☐

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

☐

Smaller reporting company o 

☐

Emerging growth company o 

☐

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

☐

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

þ

Number of shares of the registrant’s common stock outstanding at October 30, 2017: 148,696,03228, 2019: 201,028,695 shares


TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION:

iii

iv

 

Item 1. Consolidated Financial Statements (Unaudited)

iii

iv

 

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

32

33

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

57

49

 

Item 4. Controls and Procedures

59

51

PART II – OTHER INFORMATION:

60

52

 

Item 1. Legal Proceedings

60

52

 

Item 1A. Risk Factors

60

52

 

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

61

53

 

Item 6. Exhibits

62

54

i



ii

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, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims, disputes and disputes, derivative activities and potential financing.activities. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “will,” “goal” or other words that convey the uncertainty of future events, expectations or possible outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events and their potential effect on us. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by any forward-looking statements. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made. We disclaim any obligation to update or revise these statements unless required by law, whether as a result of new information, future events or otherwise, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Part II, Item 1A,1A. Risk Factors” in this Quarterly Report and in “Part I, Item 1A,1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2016,2018, 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 aboutgas, or increases in the estimated quantities ofdifferential between index oil andor natural gas reserves;

·drilling, completionprices and operating risks;

·prices received;

the effects of government regulation, permitting and other legal requirements, including new legislation or regulation ofrelated to hydraulic fracturing, andclimate change or derivatives reform;
competition in the export of oil and natural gas;

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

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

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

·industry;

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, including our ability to efficiently execute large-scale project development as we could experience delays, curtailments and other adverse impacts associated with well spacing and a high concentration of activity;
uncertainties about the estimated quantities of oil and natural gas reserves;
risks related to the concentration of our operations in the Permian Basin of West Texas and 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, 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;

·risks

difficult and liabilities associated with acquired properties or businesses;

·uncertainties about our ability to successfully execute our businessadverse conditions in the domestic and financial plansglobal capital and strategies;

·credit markets;

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

·Credit Facility, as defined herein;

the impact of potential changes in our credit ratings;

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

·

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

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

·competition in the oil and natural gas industry; and

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

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.

ii


iii

Table of Contents


PART I– FINANCIAL INFORMATION

Item 1.  Consolidated Financial Statements (Unaudited)

Item 1.Consolidated Financial Statements (Unaudited)

Consolidated Balance Sheets at September 30, 20172019 and December 31, 20162018

1

 

Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 20172019 and 20162018

2

 

Consolidated StatementStatements of Stockholders’ Equity for the Three and Nine Months Ended September 30, 20172019 and 2018

3

 

Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 20172019 and 20162018

4

5

 

Condensed Notes to Consolidated Financial Statements

5

6

iii


iv

Table of Contents


Concho Resources Inc.

Consolidated Balance Sheets

Unaudited




 

 

 

 

 

 

 

September 30,

 

 

December 31,

(in millions, except share and per share amounts)

 

 

2017

 

 

2016

Assets

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

-

 

$

53

 

Accounts receivable, net of allowance for doubtful accounts:

 

 

 

 

 

 

 

 

Oil and natural gas

 

 

271

 

 

220

 

 

Joint operations and other

 

 

223

 

 

238

 

Derivative instruments

 

 

4

 

 

4

 

Prepaid costs and other

 

 

37

 

 

31

 

 

  

Total current assets

 

 

535

 

 

546

Property and equipment:

 

 

 

 

 

 

 

Oil and natural gas properties, successful efforts method

 

 

20,754

 

 

18,476

 

Accumulated depletion and depreciation

 

 

(8,167)

 

 

(7,390)

 

 

Total oil and natural gas properties, net

 

 

12,587

 

 

11,086

 

Other property and equipment, net

 

 

232

 

 

216

 

 

Total property and equipment, net

 

 

12,819

 

 

11,302

Funds held in escrow

 

 

-

 

 

43

Deferred loan costs, net

 

 

14

 

 

11

Intangible asset - operating rights, net

 

 

24

 

 

24

Inventory

 

 

15

 

 

16

Noncurrent derivative instruments

 

 

28

 

 

-

Other assets

 

 

47

 

 

177

 

Total assets

 

$

13,482

 

$

12,119

Liabilities and Stockholders’ Equity

Current liabilities:

 

 

 

 

 

 

 

Accounts payable - trade

 

$

36

 

$

28

 

Bank overdrafts

 

 

68

 

 

-

 

Revenue payable

 

 

135

 

 

132

 

Accrued drilling costs

 

 

381

 

 

359

 

Derivative instruments

 

 

37

 

 

82

 

Other current liabilities

 

 

153

 

 

152

 

 

  

Total current liabilities

 

 

810

 

 

753

Long-term debt

 

 

2,738

 

 

2,741

Deferred income taxes

 

 

1,150

 

 

766

Noncurrent derivative instruments

 

 

6

 

 

96

Asset retirement obligations and other long-term liabilities

 

 

147

 

 

140

Commitments and contingencies (Note 9)

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

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

 

 

-

 

 

-

 

Additional paid-in capital

 

 

7,125

 

 

6,783

 

Retained earnings

 

 

1,573

 

 

884

 

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

 

 

 

 

 

 

 

 

December 31, 2016, respectively

 

 

(67)

 

 

(44)

 

 

  

Total stockholders’ equity

 

 

8,631

 

 

7,623

 

Total liabilities and stockholders’ equity

 

$

13,482

 

$

12,119

 

 

 

 

 

 

 

 

 

 

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

1

Unaudited
(in millions, except share and per share amounts)September 30,
2019
December 31,
2018
Assets
Current assets:


Cash and cash equivalents$—

$—
Accounts receivable, net of allowance for doubtful accounts:


Oil and natural gas535

466
Joint operations and other263

365
Inventory30

35
Assets held for sale930
 —
Derivative instruments201

484
Prepaid costs and other58

59
Total current assets2,017

1,409
Property and equipment:


Oil and natural gas properties, successful efforts method28,497

31,706
Accumulated depletion and depreciation(7,477)
(9,701)
Total oil and natural gas properties, net21,020

22,005
Other property and equipment, net408

308
Total property and equipment, net21,428

22,313
Deferred loan costs, net8

10
Goodwill2,141

2,224
Intangible assets, net17

19
Noncurrent derivative instruments121

211
Other assets400

108
Total assets$26,132

$26,294
Liabilities and Stockholders’ Equity
Current liabilities:


Accounts payable - trade$66

$50
Book overdrafts55

159
Revenue payable220

253
Accrued drilling costs471

574
Liabilities held for sale69
 —
Derivative instruments15

—
Other current liabilities444

320
Total current liabilities1,340

1,356
Long-term debt4,349

4,194
Deferred income taxes1,783

1,808
Noncurrent derivative instruments—

—
Asset retirement obligations and other long-term liabilities149

168
Commitments and contingencies (Note 9)



Stockholders’ equity:


Common stock, $0.001 par value; 300,000,000 authorized; 202,216,989 and 201,288,884 shares issued at September 30, 2019 and December 31, 2018, respectively—

—
Additional paid-in capital14,840

14,773
Retained earnings3,817

4,126
Treasury stock, at cost; 1,172,545 and 1,031,655 shares at September 30, 2019 and December 31, 2018, respectively(146)
(131)
Total stockholders’ equity18,511

18,768
Total liabilities and stockholders’ equity$26,132

$26,294
    


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

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

 

September 30,

 

September 30,

(in millions, except per share amounts)

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

 

$

498

 

$

348

 

$

1,461

 

$

929

 

Natural gas sales

 

 

129

 

 

82

 

 

345

 

 

181

 

 

Total operating revenues

 

 

627

 

 

430

 

 

1,806

 

 

1,110

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas production

 

 

106

 

 

71

 

 

293

 

 

240

 

Production and ad valorem taxes

 

 

48

 

 

33

 

 

140

 

 

89

 

Exploration and abandonments

 

 

7

 

 

10

 

 

42

 

 

54

 

Depreciation, depletion and amortization

 

 

284

 

 

299

 

 

848

 

 

890

 

Accretion of discount on asset retirement obligations

 

 

2

 

 

2

 

 

6

 

 

5

 

Impairments of long-lived assets

 

 

-

 

 

-

 

 

-

 

 

1,525

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ended September 30, 2017 and 2016)

 

 

64

 

 

53

 

 

180

 

 

160

 

(Gain) loss on derivatives

 

 

206

 

 

(41)

 

 

(289)

 

 

176

 

(Gain) loss on disposition of assets, net

 

 

(13)

 

 

1

 

 

(667)

 

 

(109)

 

 

Total operating costs and expenses

 

 

704

 

 

428

 

 

553

 

 

3,030

Income (loss) from operations

 

 

(77)

 

 

2

 

 

1,253

 

 

(1,920)

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(39)

 

 

(53)

 

 

(118)

 

 

(162)

 

Loss on extinguishment of debt

 

 

(65)

 

 

(28)

 

 

(66)

 

 

(28)

 

Other, net

 

 

2

 

 

(2)

 

 

18

 

 

(9)

 

 

Total other expense

 

 

(102)

 

 

(83)

 

 

(166)

 

 

(199)

Income (loss) before income taxes

 

 

(179)

 

 

(81)

 

 

1,087

 

 

(2,119)

 

Income tax (expense) benefit

 

 

66

 

 

30

 

 

(398)

 

 

782

Net income (loss)

 

 $  

(113)

 

 $  

(51)

 

 $  

689

 

 $  

(1,337)

Earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic net income (loss)

 

 $  

(0.77)

 

 $  

(0.38)

 

 $  

4.64

 

 $  

(10.18)

 

Diluted net income (loss)

 

$

(0.77)

 

$

(0.38)

 

$

4.63

 

$

(10.18)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

Unaudited

2

 Three Months Ended
September 30,		 Nine Months Ended
September 30,
(in millions, except per share amounts)2019 2018 2019 2018
Operating revenues:       
Oil sales$1,023
 $957
 $3,007
 $2,545
Natural gas sales92
 235
 339
 539
Total operating revenues1,115
 1,192
 3,346
 3,084
Operating costs and expenses:       
Oil and natural gas production190
 156
 552
 416
Production and ad valorem taxes85
 89
 255
 229
Gathering, processing and transportation25
 16
 73
 36
Exploration and abandonments26
 10
 90
 36
Depreciation, depletion and amortization488
 406
 1,431
 1,033
Accretion of discount on asset retirement obligations3
 3
 8
 7
Impairments of long-lived assets101
 —
 969
 —
General and administrative (including non-cash stock-based compensation of $20 and $23 for the three months ended September 30, 2019 and 2018, respectively, and $67 and $58 for the nine months ended September 30, 2019 and 2018, respectively)75
 84
 254
 221
(Gain) loss on derivatives(397) 625
 445
 793
(Gain) loss on disposition of assets, net(303) 5
 (303) (719)
Transaction costs—
 23
 1
 39
Total operating costs and expenses293
 1,417
 3,775
 2,091
Income (loss) from operations822
 (225) (429) 993
Other income (expense):       
Interest expense(46) (46) (141) (103)
Other, net4
 3
 311
 108
Total other income (expense)(42) (43) 170
 5
Income (loss) before income taxes780
 (268) (259) 998
Income tax (expense) benefit(222) 69
 25
 (225)
Net income (loss)$558
 $(199) $(234) $773
Earnings per share:       
Basic net income (loss)$2.78
 $(1.05) $(1.18) $4.74
Diluted net income (loss)$2.78
 $(1.05) $(1.18) $4.74
        


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

Concho Resources Inc.

Consolidated StatementStatements of Stockholders’ Equity

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common Stock

 

 

Additional

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

Issued

 

 

Paid-in

 

 

Retained

 

Treasury Stock

 

Stockholders’

(in millions, except share data)

 

Shares

 

Amount

 

 

Capital

 

 

Earnings

 

Shares

 

Amount

 

 

Equity

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

BALANCE AT DECEMBER 31, 2016

 

146,489

 

$

-

 

$

6,783

 

$

884

 

430

 

$

(44)

 

$

7,623

 

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

 

-

 

 

-

 

 

8

 

 

-

 

-

 

 

-

 

 

8

BALANCE AT JANUARY 1, 2017

 

146,489

 

 

-

 

 

6,791

 

 

884

 

430

 

 

(44)

 

 

7,631

 

Net income

 

-

 

 

-

 

 

-

 

 

689

 

-

 

 

-

 

 

689

 

Common stock issued in business combinations

 

2,177

 

 

-

 

 

291

 

 

-

 

-

 

 

-

 

 

291

 

Stock options exercised

 

20

 

 

-

 

 

-

 

 

-

 

-

 

 

-

 

 

-

 

Grants of restricted stock

 

445

 

 

-

 

 

-

 

 

-

 

-

 

 

-

 

 

-

 

Performance unit share conversion

 

249

 

 

-

 

 

-

 

 

-

 

-

 

 

-

 

 

-

 

Cancellation of restricted stock

 

(82)

 

 

-

 

 

-

 

 

-

 

-

 

 

-

 

 

-

 

Stock-based compensation

 

-

 

 

-

 

 

43

 

 

-

 

-

 

 

-

 

 

43

 

Purchase of treasury stock

 

-

 

 

-

 

 

-

 

 

-

 

168

 

 

(23)

 

 

(23)

BALANCE AT SEPTEMBER 30, 2017

 

149,298

 

$

-

 

$

7,125

 

$

1,573

 

598

 

$

(67)

 

$

8,631

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

Unaudited

3

 Three Months Ended September 30, 2019
 Common Stock Issued Additional
Paid-in
Capital		 Retained
Earnings		 Treasury Stock Total
Stockholders’
Equity
(in millions, except share data)Shares Amount   Shares Amount 
 (in thousands)       (in thousands)    
BALANCE AT JUNE 30, 2019201,765
 $—
 $14,820
 $3,284
 1,166
 $(145) $17,959
Net income—
 —
 —
 558
 —
 —
 558
Common stock dividends ($0.125 per share)—
 —
 —
 (25) —
 —
 (25)
Grants of restricted stock511
 —
 —
 —
 —
 —
 —
Performance unit share conversion—
 —
 —
 —
 —
 —
 —
Cancellation of restricted stock(59) —
 —
 —
 —
 —
 —
Stock-based compensation—
 —
 20
 —
 —
 —
 20
Purchase of treasury stock—
 —
 —
 —
 7
 (1) (1)
BALANCE AT SEPTEMBER 30, 2019202,217
 $—
 $14,840
 $3,817
 1,173
 $(146) $18,511
              
              
              
 Nine Months Ended September 30, 2019
 Common Stock Issued Additional
Paid-in
Capital		 Retained
Earnings		 Treasury Stock Total
Stockholders’
Equity
(in millions, except share data)Shares Amount   Shares Amount 
 (in thousands)       (in thousands)    
BALANCE AT DECEMBER 31, 2018201,289
 $—
 $14,773
 $4,126
 1,032
 $(131) $18,768
Net loss—
 —
 —
 (234) —
 —
 (234)
Common stock dividends ($0.375 per share)—
 —
 —
 (75) —
 —
 (75)
Grants of restricted stock772
 —
 —
 —
 —
 —
 —
Performance unit share conversion246
 —
 —
 —
 —
 —
 —
Cancellation of restricted stock(90) —
 —
 —
 —
 —
 —
Stock-based compensation—
 —
 67
 —
 —
 —
 67
Purchase of treasury stock—
 —
 —
 —
 141
 (15) (15)
BALANCE AT SEPTEMBER 30, 2019202,217
 $—
 $14,840
 $3,817
 1,173
 $(146) $18,511
              


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

Concho Resources Inc.

Consolidated Statements of Stockholders’ Equity
Unaudited
 Three Months Ended September 30, 2018
 Common Stock Issued Additional
Paid-in
Capital		 Retained
Earnings		 Treasury Stock Total
Stockholders’
Equity
(in millions, except share data)Shares Amount   Shares Amount 
 (in thousands)       (in thousands)    
BALANCE AT JUNE 30, 2018150,195
 $—
 $7,177
 $2,812
 813
 $(98) $9,891
Net loss—
 —
 —
 (199) —
 —
 (199)
Common stock issued in business combination50,915
 —
 7,549
 —
 —
 —
 7,549
Grants of restricted stock199
 —
 —
 —
 —
 —
 —
Performance unit share conversion—
 —
 —
 —
 —
 —
 —
Cancellation of restricted stock(41) —
 —
 —
 —
 —
 —
Stock-based compensation—
 —
 23
 —
 —
 —
 23
Purchase of treasury stock—
 —
 —
 —
 215
 (32) (32)
BALANCE AT SEPTEMBER 30, 2018201,268
 $—
 $14,749
 $2,613
 1,028
 $(130) $17,232
              
              
              
 Nine Months Ended September 30, 2018
 Common Stock Issued Additional
Paid-in
Capital		 Retained
Earnings		 Treasury Stock Total
Stockholders’
Equity
(in millions, except share data)Shares Amount   Shares Amount 
 (in thousands)       (in thousands)    
BALANCE AT DECEMBER 31, 2017149,325
 $—
 $7,142
 $1,840
 598
 $(67) $8,915
Net income—
 —
 —
 773
 —
 —
 773
Common stock issued in business combination50,915
 —
 7,549
 —
 —
 —
 7,549
Grants of restricted stock646
 —
 —
 —
 —
 —
 —
Performance unit share conversion446
 —
 —
 —
 —
 —
 —
Cancellation of restricted stock(64) —
 —
 —
 —
 —
 —
Stock-based compensation—
 —
 58
 —
 —
 —
 58
Purchase of treasury stock—
 —
 —
 —
 430
 (63) (63)
BALANCE AT SEPTEMBER 30, 2018201,268
 $—
 $14,749
 $2,613
 1,028
 $(130) $17,232
              

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

Concho Resources Inc.
Consolidated Statements of Cash Flows

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

  

 

 

 

 

 

September 30,

(in millions)

 

2017

 

2016

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

Net income (loss)

 

$

689

 

$

(1,337)

 

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

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

848

 

 

890

 

 

Accretion of discount on asset retirement obligations

 

 

6

 

 

5

 

 

Impairments of long-lived assets

 

 

-

 

 

1,525

 

 

Exploration and abandonments, including dry holes

 

 

29

 

 

47

 

 

Non-cash stock-based compensation expense

 

 

43

 

 

43

 

 

Deferred income taxes

 

 

392

 

 

(768)

 

 

Gain on disposition of assets, net

 

 

(667)

 

 

(109)

 

 

(Gain) loss on derivatives

 

 

(289)

 

 

176

 

 

Net settlements received from derivatives

 

 

126

 

 

582

 

 

Loss on extinguishment of debt

 

 

66

 

 

28

 

 

Other non-cash items

 

 

1

 

 

10

 

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

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 

(61)

 

 

61

 

 

 

Prepaid costs and other

 

 

(1)

 

 

7

 

 

 

Inventory

 

 

(1)

 

 

2

 

 

 

Accounts payable

 

 

7

 

 

9

 

 

 

Revenue payable

 

 

5

 

 

(57)

 

 

 

Other current liabilities

 

 

(8)

 

 

(95)

 

 

 

 

Net cash provided by operating activities

 

 

1,185

 

 

1,019

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

Capital expenditures on oil and natural gas properties

 

 

(1,958)

 

 

(927)

 

Additions to property, equipment and other assets

 

 

(34)

 

 

(20)

 

Proceeds from the disposition of assets

 

 

803

 

 

296

 

Direct transaction costs for disposition of assets

 

 

(18)

 

 

-

 

Funds held in escrow

 

 

-

 

 

(81)

 

Contributions to equity method investments

 

 

-

 

 

(51)

 

  

 

 

Net cash used in investing activities

 

 

(1,207)

 

 

(783)

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Proceeds from issuance of debt

 

 

2,267

 

 

-

 

Payments of debt

 

 

(2,255)

 

 

(600)

 

Debt extinguishment costs

 

 

(63)

 

 

(21)

 

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

 

 

-

 

 

(1)

 

Net proceeds from issuance of common stock

 

 

-

 

 

1,327

 

Payments for loan costs

 

 

(25)

 

 

-

 

Purchase of treasury stock

 

 

(23)

 

 

(11)

 

Increase in bank overdrafts

 

 

68

 

 

-

 

  

 

 

Net cash provided by (used in) financing activities

 

 

(31)

 

 

694

 

  

 

 

Net increase (decrease) in cash and cash equivalents

 

 

(53)

 

 

930

Cash and cash equivalents at beginning of period

 

 

53

 

 

229

Cash and cash equivalents at end of period

 

$

-

 

$

1,159

NON-CASH INVESTING AND FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Issuance of common stock for business combinations

 

$

291

 

$

231

 

 

 

 

 

 

 

 

 

 

 

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

 

 

Unaudited

4

 Nine Months Ended
September 30,
(in millions)2019 2018
CASH FLOWS FROM OPERATING ACTIVITIES:   
Net income (loss)$(234) $773
Adjustments to reconcile net income (loss) to net cash provided by operating activities:   
Depreciation, depletion and amortization1,431
 1,033
Accretion of discount on asset retirement obligations8
 7
Impairments of long-lived assets969
 —
Exploration and abandonments68
 20
Non-cash stock-based compensation expense67
 58
Deferred income taxes(25) 225
Net gain on disposition of assets and other non-operating items(591) (719)
Loss on derivatives445
 793
Net settlements paid on derivatives(57) (238)
Other(6) (94)
Changes in operating assets and liabilities, net of acquisitions and dispositions:   
Accounts receivable(19) (57)
Prepaid costs and other(1) (15)
Inventory2
 (12)
Accounts payable16
 (27)
Revenue payable(20) 62
Other current liabilities14
 52
Net cash provided by operating activities2,067
 1,861
CASH FLOWS FROM INVESTING ACTIVITIES:   
Additions to oil and natural gas properties(2,385) (1,669)
Acquisitions of oil and natural gas properties(34) (105)
Additions to property, equipment and other assets(82) (53)
Proceeds from the disposition of assets393
 260
Deposit for pending divestiture of oil and natural gas properties93
 —
Direct transaction costs for asset acquisitions and dispositions(5) (3)
Distribution from equity method investment—
 148
Net cash used in investing activities(2,020) (1,422)
CASH FLOWS FROM FINANCING ACTIVITIES:   
Borrowings under credit facility2,680
 2,408
Payments on credit facility(2,527) (2,537)
Issuance of senior notes, net—
 1,595
Repayments of RSP debt—
 (1,690)
Debt extinguishment costs—
 (83)
Payments for loan costs—
 (16)
Payment of common stock dividends(75) —
Purchases of treasury stock(15) (63)
Decrease in book overdrafts(104) (29)
Other(6) —
Net cash used in financing activities(47) (415)
Net increase in cash and cash equivalents—
 24
Cash and cash equivalents at beginning of period—
 —
Cash and cash equivalents at end of period$—
 $24
NON-CASH INVESTING AND FINANCING ACTIVITIES:   
Issuance of common stock for business combinations$—
 $7,549
    

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

5

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

2019

Unaudited



Note 1. Organization and nature of operations

Concho Resources Inc. (the “Company”) is, a Delaware corporation formed on February 22, 2006. The Company’s principal business(the “Company”), is an independent oil and natural gas company engaged in the acquisition, development, exploration and production of oil and natural gas propertiesproperties. The Company's operations are primarily locatedfocused in the Permian Basin of southeastWest Texas and Southeast New Mexico and west Texas.Mexico.

Note 2. SummaryBasis of presentation and summary of significant accounting policies

A complete discussion of the Company’s significant accounting policies is included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 Form 10-K”).
Principles of consolidation.The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The Company consolidates the financial statements of these entities. The consolidated financial statements also include the accounts of a variable interest entity (“VIE”) where the Company is the primary beneficiary of the arrangements. See Note 4 for additional information regarding the circumstances surrounding the VIE. All material intercompany balances and transactions have been eliminated.

Reclassifications.Certain prior period amounts have been reclassified to conform to the 20172019 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 principlesGenerally Accepted Accounting Principles in the United States of America (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved oil and natural gas reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks and prevailing market rates of other sources of income and costs. Other significant estimates include, but are not limited to, asset retirement obligations, goodwill, fair value of stock-based compensation, fair value of business combinations, fair value of nonmonetary exchanges,transactions, fair value of derivative financial instruments and income taxes.

Assets held for sale. On August 29, 2019, the Company entered into a definitive agreement to sell its New Mexico Shelf assets and has reflected the related assets and liabilities as held for sale in the consolidated balance sheet at September 30, 2019. Refer to Note 4 for further information regarding the Company’s pending sale of its New Mexico Shelf assets.
On the date at which the Company determined the asset group met all of the held for sale criteria, the Company discontinued the recording of depletion and depreciation of the asset or asset group to be sold and reclassified it as held for sale in the accompanying consolidated balance sheets. These assets held for sale were measured at the fair value less cost to sell.
Interim financial statements.The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 20162018 is derived from audited consolidated financial statements. In the opinion of management, the accompanying consolidated financial statements reflect all adjustments necessary to present fairly the Company’s consolidated financial statements. All such adjustments are of a normal, recurring nature. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed in or omitted from these consolidated financial statements. Accordingly, these condensed notes to the consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in the Company’s Annual Report on2018 Form 10-K for the year ended December 31, 2016.

Cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. At December 31, 2016, the majority of the Company’s cash was invested in stable value government money market funds.

10-K.

5

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

Unaudited

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

The Company ownedowns a 50 percent membership interest in Beta Holding Company, LLC, a midstream joint venture Alpha Crude Connector, LLC (“ACC”), that operatedformed to construct a crude oil gathering and transportation system in the Northern DelawareMidland Basin. In February 2017, the
The Company closed on the divestiture of its ownershipowns a 20 percent membership interest in ACC. See Note 4 for additional information regardingSolaris Midstream Holdings, LLC, an entity that owns and operates water gathering, transportation, disposal, recycling and storage infrastructure assets in the dispositionPermian Basin.

6
Table of ACC.

Contents

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

The Company accounted forowns a preferred membership interest in WaterBridge Operating LLC, an entity that operates and manages various water infrastructure assets located in the Permian Basin.
The Company includes its investment in ACC under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment in ACC was approximately $129 million at December 31, 2016, and was includedbalance in other assets inon the Company’s consolidated balance sheet. Gainssheets. The Company records its share of equity investment earnings and losses incurred from the Company’s equity investment in ACC were recorded in other income (expense) in itson the consolidated statements of operations.

The Company ownsrecorded equity method investment income of $15 million and $5 million for the nine months ended September 30, 2019 and 2018, respectively. The Company also contributed certain water infrastructure assets and recorded a gain of $299 million, which is included in gain on disposition of assets, net on the Company’s consolidated statements of operations for the three and nine months ended September 30, 2019.

Until May 2019, the Company owned a 23.75 percent membership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that operatesowned and operated Oryx I, a crude oil gathering and transportation system in the Southern Delaware Basin.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 accounts for its investment in Oryx underreceived a distribution of approximately $157 million. Of this amount, approximately $54 million fully offset the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment in Oryx. The net investment of $54 million included $45 million of Company's contributions made to Oryx wasand $9 million of equity income. The remaining distribution of approximately $47$103 million and $42 million at September 30, 2017 and December 31, 2016, respectively, and is included in other assets in the Company’s consolidated balance sheets. Gains and losses incurred from the Company’s equity investment in Oryx arewas recorded in other income (expense) on the Company’s consolidated statement of operations. 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 recorded a gain in other income (expense) on the Company’s consolidated statement of operations for the nine months ended September 30, 2019. 
Litigation contingencies. The Company is a party to proceedings and claims incidental to its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. The amount of any resulting losses may differ from these estimates. An accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable. See Note 9 for additional information.
Revenue recognition. The Company recognizes revenues from the sales of oil and natural gas to its customers and presents them disaggregated on the Company’s consolidated statements of operations.

Revenue recognition. Oil and natural gas All revenues are recorded atrecognized in the timegeographical region of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. Permian Basin.

The Company follows the sales method of accounting forenters into contracts with customers to sell its oil and natural gas sales, recognizing revenues basedproduction. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with Customers,” (“ASC 606”). Specifically, revenue is recognized when the Company’s actual proceeds fromperformance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to purchasers.receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. At September 30, 2019 and December 31, 2018, the Company had receivables related to contracts with customers of $535 million and $466 million, respectively.
Oil Contracts. The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing which is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred after the transfer of control of the oil, the differentials are included in oil sales on the consolidated statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in gathering, processing and transportation on the Company’s consolidated statements of operations and are accounted for as costs incurred directly and not netted from the transaction price.
Natural Gas Contracts. The majority of the Company’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. The natural gas is sold under (i) percentage of proceeds processing contracts, (ii) fee-based contracts or (iii) a hybrid of percentage of proceeds and fee-based contracts. Under the majority of the Company’s contracts, the purchaser gathers the natural gas in the field where it is produced and transports it via pipeline to natural gas processing plants where natural gas liquid products are extracted. The natural gas liquid products 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

7
Table of Contents

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those activities, revenue is recognized on a gross basis, and the related costs are classified in gathering, processing and transportation on the Company’s consolidated statements of operations.
The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and records such reimbursements as reductions ofto general and administrative expense. The Company earned reimbursements of approximatelySuch fees totaled $5 million and $4 million for each of the three months ended September 30, 20172019 and 20162018, respectively, and approximately $12$13 million for each ofboth the nine months ended September 30, 20172019 and 2016.

Recently adopted accounting pronouncements. 2018.

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, 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, which includes a control premium, plus 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 adopted Accounting Standards Update (“ASU”) No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvementsperformed a 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 4, in August 2019, the Company entered into a definitive agreement to Employee Share-based Payment Accounting,” on January 1, 2017. The adoption did not have an impact on prior period consolidated financial statements.sell its assets in the New Mexico Shelf. The Company electedclassified these assets as held for sale at August 29, 2019. The Company allocated $81 million of goodwill to account for forfeituresthis disposal group, all of share-based payments as they occur. At December 31, 2016,which the Company had notimpaired. This impairment charge was recorded compensation expensein impairments of approximately $8 million based on forecasted forfeitures nor the associated deferred tax benefit of approximately $3 million. 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 taxes by approximately $8 million. The Company elected to prospectively classify excess tax benefits and deficiencies as operating activitieslong-lived assets 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 nine months ended September 30, 2017, the Company recorded excess tax benefits of approximately $6 million as offsets to the Company’s income tax provision. Also under the new standard,operations for the three and nine months ended September 30, 2017,2019. See Note 6 for additional impairment discussion of this disposal group. In conjunction with the allocation and 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 forfeituresas the fair value of share-based paymentsthe reporting unit exceeded the carrying value.
The Company also performed an impairment test at September 30, 2019 due to a decline in the Company’s market capitalization during the third quarter of approximately $1 million2019. The fair value of the reporting unit at September 30, 2019 exceeded the carrying value of net assets, and $7 million, respectively.

Newno additional impairment charges were recorded during the third quarter of 2019. As a result of the aforementioned impairment charge recorded during the current quarter, the Company's goodwill balance decreased from $2.2 billion at December 31, 2018 to $2.1 billion at September 30, 2019.

A decrease in the Company's enterprise value could lead to an impairment of goodwill in future periods. 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 an impairment of the Company's goodwill balance.
Recently adopted accounting pronouncements issued but not yet adopted. pronouncements.In May 2014,February 2016, the Financial Accounting Standards Board (the “FASB”(“FASB”) issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue

6

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

Unaudited

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

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

In February 2016, the FASB issued ASUAccounting Standards Update (“ASU”) No. 2016-02, “Leases (Topic 842),” (“ASU 2016-02”), which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the consolidated balance sheet while maintaining substantially similar classifications for financingfinance and operating leases. Lease expense recognition on the consolidated statements of operations will bewas effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company doesadopted this guidance on January 1, 2019. The Company made policy elections not plan to early adoptcapitalize 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

8
Table of Contents
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

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. TheUpon adoption, the Company is currently in the process of reviewing all contracts that could be applicable to this new guidance. The Company believes this new guidance will have a moderate impact to its consolidated balance sheets due to the 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 liabilitiesliabilities. See Note 9 for additional disclosures of the Company’s leases.
In August 2018, the Securities and Exchange Commission (“SEC”) issued a final rule that amends certain of its disclosure requirements that have become redundant, duplicative, overlapping, outdated or superseded, in light of other disclosure requirements, U.S. GAAP or changes in the information environment. The amendments are intended to facilitate the disclosure of information to investors and simplify compliance without significantly altering the total mix of information provided to investors. The final rule amends numerous SEC rules, items and forms covering a diverse group of topics, including, but not 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. As a result, the Company updated its presentation of the consolidated statements of stockholders’ equity to include comparative periods in the prior year. In addition, the final rule requires the presentation of dividends per share to be disclosed in the statement of stockholders’ equity.

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

In January 2017,November 2018, the FASB issued ASU No. 2017-01, “Business Combinations2018-18, “Collaborative Arrangements (Topic 805)808): Clarifying the Definition of a Business,” with the objective of adding guidance to assist in evaluating whetherInteraction 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 asset acquisitions or as business combinations. Therevenue under Topic 606 when the collaborative arrangement participant is a customer in the context of a unit of account, (ii) adds unit-of-account guidance providesin Topic 808 to align with the guidance in Topic 606 and (iii) requires that in a screentransaction with a collaborative arrangement participant that is not directly related to determine when an integrated set of assets and activitiessales to third parties, presenting the transaction together with revenue recognized under Topic 606 is precluded if the collaborative arrangement participant 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 guidancecustomer. ASU 2018-18 is effective for annual periodsfiscal years beginning after December 15, 2017,2019, and interim periods within those fiscal years and early adoption is allowed.permitted. The amendments in this update should be applied retrospectively to the date of initial application of Topic 606. An entity should recognize the cumulative effect of initially applying the amendments as an adjustment to the opening balance of retained earnings of the later of the earliest annual period presented and the annual period that includes the date of the entity’s initial application of Topic 606. The Company is evaluating the impactdoes not believe this new guidance will have a material impact on its consolidated financial statements.

7


9

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

2019

Unaudited


Note 3.Exploratory RSP Acquisition
On July 19, 2018, the Company completed the acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”) for approximately $7.5 billion. In connection with the RSP Acquisition, the Company incurred approximately $23 million and $33 million of costs related to consulting, investment banking, advisory, legal and other acquisition-related fees during the three and nine months ended September 30, 2018, respectively, which are included in transaction costs in operating costs and expenses on the consolidated statements of operations. 
Purchase price allocation. The RSP Acquisition has been accounted for as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price of RSP to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Any value assigned to goodwill is not deductible for income tax purposes.
The following table sets forth the Company’s final purchase price allocation:
(in millions) 
Total purchase price$7,549
  
Fair value of liabilities assumed: 
Accounts payable – trade$48
Accrued drilling costs79
Current derivative instruments10
Other current liabilities116
Long-term debt1,758
Deferred income taxes515
Asset retirement obligations20
Noncurrent derivative instruments5
Total liabilities assumed$2,551
  
Total purchase price plus liabilities assumed$10,100
  
Fair value of assets acquired: 
Accounts receivable$194
Current derivative instruments36
Other current assets21
Proved oil and natural gas properties4,055
Unproved oil and natural gas properties3,565
Other property and equipment5
Noncurrent derivative instruments2
Implied goodwill2,222
Total assets acquired$10,100
  


10
Table of Contents
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

Pro forma data. The following unaudited pro forma combined condensed financial data for the three and nine months ended September 30, 2018 was derived from the historical financial statements of the Company giving effect to the RSP Acquisition as if it had occurred on January 1, 2017. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for RSP’s outstanding shares of common stock, as well costs

The Company capitalizes exploratory well costs until a determination is madeas pro forma adjustments based on available information and certain assumptions that the well has either foundCompany 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 reserves or that it is impaired. After an exploratory well has been completed and found oil and natural gas reserves, a determination may be pending as to whetherproperties and (iii) the oil and natural gas reserves can be classified as proved. In those circumstances, the Company continues to capitalize the well or project costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viabilityestimated tax impacts of the project.pro forma adjustments.

The capitalized exploratory well costs are carried in unproved oilpro 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 natural gas properties. See Note 15 foris not necessarily indicative of the provedresults that might have occurred had the RSP Acquisition taken place on January 1, 2017 and unproved components of oil and natural gas properties. If the exploratory well is determinednot intended to be impaired, the well costs are charged to explorationa projection of future results.
(in millions, except per share amounts)Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
Operating revenues$1,243
 $3,741
Net income (loss)$(133) $1,039
Earnings per share:   
Basic net income (loss)$(0.67) $5.19
Diluted net income (loss)$(0.67) $5.19
    

Note 4. Other acquisitions, divestitures and abandonments expense in the consolidated statements of operations.

The following table reflects the Company’s net capitalized exploratory well activity duringnonmonetary transactions

During the nine months ended September 30, 2017:

 

 

 

 

 

 

 

 

 

 

 

  

Nine Months Ended

(in millions)

 

  

September 30, 2017

 

 

 

 

 

 

 

 

Beginning capitalized exploratory well costs

 

 

 

 

$

151

 

Additions to exploratory well costs pending the determination of proved reserves

 

 

 

 

 

255

 

Reclassifications due to determination of proved reserves

 

 

 

 

 

(136)

Ending capitalized exploratory well costs

 

 

 

 

$

270

 

 

 

 

 

 

 

 

The2019, the Company entered into the following table provides an agingtransaction:

New Mexico Shelf divestiture. On August 29, 2019, the Company entered into a definitive agreement to sell its assets in the New Mexico Shelf for cash proceeds of $925 million, subject to customary closing and post-closing adjustments. In conjunction with the execution of this agreement, the Company received a cash deposit of $93 million from the buyer, which was included in other current liabilities on the consolidated balance sheet at September 30, 20172019. The Company determined these assets and December 31, 2016 of capitalized exploratory well costs basedliabilities to be held for sale at August 29, 2019 and classified them as current assets and liabilities held for sale on the date drilling was completed:

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

 

December 31,

(in millions, except number of projects)

 

 

2017

 

 

2016

 

 

 

 

 

 

 

 

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

  

$

266

 

$

141

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

  

 

4

 

  

10

 

Total capitalized exploratory well costs

  

$

270

 

$

151

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

 

 

 

 

 

 

 

than one year

 

 

4

 

 

8

 

 

  

 

 

 

 

 

8

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

consolidated balance sheet. Additionally, an impairment charge of $3 million, included in impairments of long-lived assets on the Company's consolidated statements of operations for the three and nine months ended September 30, 2017

Unaudited

Note 4. Acquisitions2019, was recorded to reduce the carrying value of these assets to their estimated fair value less costs to sell. The total assets held for sale of $930 million relate primarily to oil and divestitures

Midland Basin acquisition.In July 2017,natural gas properties, while the total liabilities held for sale of $69 million relate to $59 million of asset retirement obligations and $10 million of revenue payable. This transaction is expected to close in November 2019 and is subject to customary terms and conditions.

During the nine months ended September 30, 2018, the Company completedclosed the following transactions:
February 2018 acquisition and divestiture. In February 2018, the Company closed an acquisition treated as a business combination where it received producing wells along with approximately 21,000 net acres, primarily located in the Midland Basin. As consideration for the non-cash acquisition, the Company paiddivested of certain producing wells and approximately $595 million34,000 net acres located primarily in cash. The acquisition is subject to customary post-closing adjustments.

Concurrent with the acquisition, the Company entered into a transaction structured as a reverse like-kind exchange (“Reverse 1031 Exchange”) in accordance with Section 1031northern portion of the Internal Revenue Code of 1986,Delaware Basin. The business acquired was valued at approximately $755 million as amended (the “Code”). In connection withcompared to the Reverse 1031 Exchange, the Company assigned the ownershiphistorical book value of the oil and natural gas properties acquired todivested assets of approximately $180 million, which resulted in a VIE formed by an exchange accommodation titleholder. The Company operates the properties pursuant to a management agreement with the VIE. At September 30, 2017, the Company was determined to be the primary beneficiarynon-cash gain of the VIE, as the Company had the ability to control the activities that most significantly impact the VIE’s economic performance. Theapproximately $575 million, included in gain on disposition of assets, currently held by the VIE attributable to the acquisition will be conveyed to the Company or one of its subsidiaries, and the VIE structure will terminate, upon the earlier of (i) the completion of the Reverse 1031 Exchange or (ii) the expiration of the time allowed by the treasury regulations and published Internal Revenue Service guidance to complete the Reverse 1031 Exchange, which is 180 days from commencement. At September 30, 2017, the VIE’s total assets and liabilities included innet on the Company’s consolidated balance sheet were approximately $607 million and $605 million, respectively.

Northern statement of operations for the nine months ended September 30, 2018.

Delaware Basin acquisition. divestitures.In April 2017,January 2018, the Company closed on the remaindertwo asset divestitures of its acquisitioncertain non-core assets in the Northern Delaware Basin. As consideration for the entire acquisition, the Company paid approximately $160 million in cash, of which $43 million was held in escrow at December 31, 2016,Reeves and issued to the seller approximately 2.2 million shares of its common stockWard Counties, Texas, 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 cashcombined proceeds from the sale of approximately $801$280 million. After direct transaction costs, the Company recorded a pre-tax gain of approximately $134 million, which is included in gain on disposition of assets, net on its consolidated statement of operations for the nine months ended September 30, 2018. The assets divested included proved and unproved oil and natural gas properties on approximately 20,000 net acres.

Nonmonetary transactions. During the nine months ended September 30, 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 $655 million. The Company’s net investment in ACC at the time

11
Table of closing was approximately $129 million.Contents

9

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

2019

Unaudited


$15 million, included in gain on disposition of assets, net on the Company’s consolidated statement of operations for the nine months ended September 30, 2018.
Note 5.Stock incentive plan

The

On May 16, 2019, the Company’s 2015stockholders approved and adopted the Company’s 2019 Stock Incentive Plan (“the Plan”), which, among other things, increased the total shares authorized for issuance from 10.5 million to 15 million. The Plan provides for granting stock options, restricted stock awards and performance unit awards to directors, officers and employees of the Company. The restricted stock-based compensationstock awards generally vest over a period ranging from one to eightten years.

The holders of unvested restricted stock awards have voting rights and the right to receive dividends.

In January 2019, the Company granted 212,947 performance unit awards. Included in this grant were 38,952 performance unit awards granted to certain officers, of which 19,476 have a three-year performance period and 19,476 have a five-year performance period. 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.
Shares issued as a result of awards granted under the Plan are generally new common shares.
A summary of the Company’s Stock Incentiverestricted stock shares and performance unit activity under the Plan activity for the nine months ended September 30, 20172019 is presented below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted

 

Stock

 

Performance

 

 

 

 

Stock Shares

 

Options

 

Units

 

 

 

 

 

 

 

 

 

 

 

 

 

Outstanding at December 31, 2016

 

  

1,157,270

 

 

20,000

 

 

331,526

 

 

Awards granted (a)

 

  

445,384

 

 

-

 

 

108,398

 

 

Options exercised

 

  

-

 

 

(20,000)

 

 

-

 

 

Awards cancelled / forfeited

 

  

(82,200)

 

 

-

 

 

(43,333)

 

 

Lapse of restrictions

 

 

(389,965)

 

 

-

 

 

-

 

Outstanding at September 30, 2017

 

1,130,489

 

-

 

396,591

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

121.77

 

$

-

 

$

183.48

 

 

 

 

  

 

 

 

 

 

 

 

 
Restricted
Stock Shares
 
Performance
Units
 
Outstanding at December 31, 20181,364,699
 218,391
 
Awards granted (a)771,789
 212,947
(b)
Awards canceled / forfeited(89,998) —
 
Lapse of restrictions(477,303) —
 
Outstanding at September 30, 20191,569,187
 431,338
 
     
(a) Weighted average grant date fair value per share/unit$98.98
 $144.03
 
(b) 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.


The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at September 30, 2017:

2019:

 

 

 

 

 

(in millions)

 

 

 

 

 

 

 

 

Remaining 2017

 

$

17

2018

 

  

47

2019

 

  

25

Thereafter

 

 

8

 

Total

  

$

97

 

 

 

 

 

(in millions) 
Remaining 2019$22
202063
202137
202213
20232
20241
Thereafter2
Total$140
  

10


12

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

2019

Unaudited


Note 6. Disclosures about fair value measurements

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

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

Level 2:

Level 1:
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2:
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, collars and floors, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.
Level 3:
Prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.








13
Table 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. Contents

11

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

2019

Unaudited


Financial Assets and Liabilities Measured at Fair Value

The following table presents the carrying amounts and fair values of the Company’s financial instruments at September 30, 20172019 and December 31, 2016:

2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2017

 

December 31, 2016

 

 

 

Carrying

 

Fair

 

Carrying

 

Fair

(in millions)

(in millions)

 

Value

 

Value

 

Value

 

Value

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

 

 

 

 

 

 

 

 

 

 

   
Assets:   
Derivative instruments$322
$322
 $695
$695

Assets:

 

 

 

 

 

 

 

 

   
Liabilities:   
Derivative instruments$15
$15
 $—
$—
Credit facility$395
$395
 $242
$242
$600 million 4.375% senior notes due 2025 (a)$594
$622
 $594
$591
$1,000 million 3.75% senior notes due 2027 (a)$990
$1,043
 $989
$939
$1,000 million 4.3% senior notes due 2028 (a)$989
$1,081
 $988
$980
$800 million 4.875% senior notes due 2047 (a)$789
$914
 $789
$761
$600 million 4.85% senior notes due 2048 (a)$592
$689
 $592
$573

 

Derivative instruments

 

$

32

 

$

32

 

$

4

 

$

4

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Derivative instruments

 

$

43

 

$

43

 

$

178

 

$

178

 

Credit facility

 

$

368

 

$

368

 

$

-

 

$

-

 

$600 million 5.5% senior notes due 2022 (a)

 

$

-

 

$

-

 

$

594

 

$

620

 

$1,550 million 5.5% senior notes due 2023 (a)

 

$

-

 

$

-

 

$

1,555

 

$

1,621

 

$600 million 4.375% senior notes due 2025 (a)

 

$

593

 

$

632

 

$

592

 

$

599

 

$1,000 million 3.75% senior notes due 2027 (a)

 

$

988

 

$

1,006

 

$

-

 

$

-

 

$800 million 4.875% senior notes due 2047 (a)

 

$

789

 

$

834

 

$

-

 

$

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

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

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


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

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

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

12


14
Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification,even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at September 30, 20172019 and December 31, 2016.2018. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2017

 

 

 

 

 

Fair Value Measurements Using

 

 

 

Net

 

 

 

 

 

Quoted Prices

 

 

 

 

 

 

 

 

 

 

 

Gross

 

 

Fair Value

 

 

 

 

 

in Active

 

 

Significant

 

 

 

 

 

 

 

 

Amounts

 

 

Presented

 

 

 

 

 

Markets for

 

 

Other

 

 

Significant

 

 

 

 

 

Offset in the

 

 

in the

 

 

 

 

 

Identical

 

 

Observable

 

 

Unobservable

 

 

 

 

 

Consolidated

 

 

Consolidated

 

 

 

 

 

Assets

 

 

Inputs

 

 

Inputs

 

 

Total

 

 

Balance

 

 

Balance

(in millions)

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

Fair Value

 

 

Sheet

 

 

Sheet

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

-

 

$

35

 

$

-

 

$

35

 

$

(31)

 

$

4

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

    

44

 

    

-

 

    

44

 

    

(16)

 

    

28

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

 

(68)

 

 

-

 

 

(68)

 

 

31

 

 

(37)

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

    

(22)

 

    

-

 

    

(22)

 

    

16

 

    

(6)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net derivative instruments

 

$

-

 

$

(11)

 

$

-

 

$

(11)

 

$

-

 

$

(11)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

13

September 30, 2019
(in millions)Fair Value Measurements Using      
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
Fair
Value
 
Gross
Amounts
Offset in the
Consolidated
Balance
Sheet
 
Net
Fair Value
Presented
in the
Consolidated
Balance
Sheet
Assets:           
Current:           
Commodity derivatives$—
 $302
 $—
 $302
 $(101) $201
Noncurrent:           
Commodity derivatives—
 147
 —
 147
 (26) 121
            
Liabilities:           
Current:           
Commodity derivatives—
 (116) —
 (116) 101
 (15)
Noncurrent:           
Commodity derivatives—
 (26) —
 (26) 26
 —
            
Net derivative instruments$—
 $307
 $—
 $307
 $—
 $307
            

15

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

Unaudited

2019
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

 

 

 

 

Fair Value Measurements Using

 

 

 

Net

 

 

 

 

 

Quoted Prices

 

 

 

 

 

 

 

 

 

 

 

Gross

 

 

Fair Value

 

 

 

 

 

in Active

 

 

Significant

 

 

 

 

 

 

 

 

Amounts

 

 

Presented

 

 

 

 

 

Markets for

 

 

Other

 

 

Significant

 

 

 

 

 

Offset in the

 

 

in the

 

 

 

 

 

Identical

 

 

Observable

 

 

Unobservable

 

 

 

 

 

Consolidated

 

 

Consolidated

 

 

 

 

 

Assets

 

 

Inputs

 

 

Inputs

 

 

Total

 

 

Balance

 

 

Balance

(in millions)

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

Fair Value

 

 

Sheet

 

 

Sheet

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

-

 

$

59

 

$

-

 

 $  

59

 

 $  

(55)

 

 $  

4

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

-

 

  

-

 

    

-

 

    

-

 

    

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

(137)

 

  

-

 

    

(137)

 

    

55

 

    

(82)

 

 

Noncurrent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

 

-

 

  

(96)

 

  

-

 

    

(96)

 

    

-

 

    

(96)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net derivative instruments

 

$

-

 

$

(174)

 

$

-

 

 $  

(174)

 

 $  

-

 

 $  

(174)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unaudited


December 31, 2018
 Fair Value Measurements Using      
(in millions)
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
Fair
Value
 
Gross
Amounts
Offset in the
Consolidated
Balance
Sheet
 
Net
Fair Value
Presented
in the
Consolidated
Balance
Sheet
Assets:           
Current:           
Commodity derivatives$—
 $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 September 30, 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.

The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 7 for additional information regarding the Company’s derivative activities and counterparties.

14


16

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

2019

Unaudited


Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

values. 

Impairments of long-lived assets – .The Company periodically reviews its long-lived assets to be held and used, including proved oil and natural gas properties, and their integrated assets, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. The Company reviews its oil and natural gas properties by depletion base. 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 was included in impairments of long-lived assets on the consolidated statement of operations for the nine months ended September 30, 2019. The 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.

The assumptions used in calculating the estimated fair value of the Yeso field at June 30, 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 SeptemberJune 30, 2017, 2019, the Company’s estimates of commodity prices for purposes of determining undiscounted future cash flows, which arewere based on the NYMEX strip, ranged from a 20172019 price of $52.29$58.32 per barrel of oil decreasing to a 20212022 price of $50.77 per barrel of oil partially recovering$53.58 then rising to a 20242026 price of $52.01$54.47 per barrel of oil. Similarly, naturalNatural gas prices ranged from a 20172019 price of $3.14$2.38 per Mcf of natural gas decreasingincreasing to a 20202026 price of $2.85$2.99 per Mcf ofMcf. Both oil and natural gas partially recovering to a 2024 price of $2.88 per Mcf of natural gas. Commoditycommodity prices for this purpose were held flat after 2024.

2026.

The Company calculates the estimated fair values of its long-lived assets and their integrated assets using a discounted future cash flow model. Fair value assumptionsSignificant inputs associated with the calculation of discounted future net cash flows include estimates of (i) market estimatesrecoverable 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 reservespurposes 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 probablequality differentials. Both oil and possible reserves, (vii) prevailing market rates of income and expenses from integrated assets and (viii) a 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 annuala rate of 10 percentpercent.
Due to determine fair value. These are classified as Level 3 fair value assumptions.

Duringthe decrease in future commodity prices after June 30, 2019, the Company further impaired the Yeso Field and recorded an impairment charge of $20 million during the three months ended March 31, 2016, NYMEX strip prices declined as compared to December 31, 2015, and as a result the carrying amount of the Company’s Yeso field of approximately $3.4 billion exceeded the expected undiscounted future net cash flows resulting in a non-cash charge against earnings of approximately $1.5 billion. The non-cash charge represented the amount by which the carrying amount exceeded the estimated fair value of the assets.

The following table reports the carrying amount, estimated fair value and impairment expense of long-lived assets for the indicated period:

September 30, 2019.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Estimated

 

 

 

 

 

 

Carrying

 

 

Fair Value

 

 

Impairment

(in millions)

 

 

 Amount 

 

 

(Level 3)

 

 

Expense

 

 

 

 

 

 

 

 

 

 

March 2016

 

$

3,438

 

$

1,913

 

$

1,525

 

 

 

 

 

 

 

 

 

 

It is reasonably possible that the estimate of undiscounted future net cash flows of the Company’s long-lived assets may change in the future resulting in the need to further 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)

15

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

Unaudited

future reserve volume adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) results of future drilling activities and (v) changes in income and expenses from integrated assets.

Assets held for sale. The Company's Yeso field is primarily composed of the New Mexico Shelf assets that the Company expects to sell in November 2019. The assets and liabilities associated with the pending 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 was based upon anticipated sales proceeds less costs to sell. The anticipated proceeds are equal to the $925 million base purchase price less estimated customary closing and post-closing adjustments. Because the Company's closing and post-closing adjustments, primarily revenues and operating expenses, used to calculate the fair value less costs to sell are estimates that are both significant and unobservable, they are considered Level 3 fair value measurements. Refer to Note 4 for additional information related to the New Mexico Shelf asset divestiture.


17

Table of Contents
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

Note 7. Derivative financial instruments

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

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

The following table summarizes the amounts reported in earnings related to the commodity derivative instruments for the three and nine months ended September 30, 20172019 and 2016:

2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

 

 

September 30,

 

September 30,

 

(in millions)

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) on derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil derivatives

 

$

(205)

 

$

36

 

$

260

 

$

(173)

 

 

Natural gas derivatives

 

 

(1)

 

 

5

 

 

29

 

 

(3)

 

 

 

Total

 

$

(206)

 

$

41

 

$

289

 

$

(176)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

 

 

September 30,

 

September 30,

 

(in millions)

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash receipts from (payments on) derivatives:

 

 

 

 

 

 

 

 

 

 

 

Oil derivatives

 

$

28

 

$

154

 

$

129

 

$

566

 

 

Natural gas derivatives

 

  

2

 

    

1

 

    

(3)

 

    

16

 

 

 

Total

 

$

30

 

$

155

 

$

126

 

$

582

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

16

 Three Months Ended
September 30,		 Nine Months Ended
September 30,
(in millions)2019 2018 2019 2018
Gain (loss) on derivatives:       
Oil derivatives$355
 $(626) $(506) $(787)
Natural gas derivatives42
 1
 61
 (6)
Total$397
 $(625) $(445) $(793)
        
The following table represents the Company’s net cash receipts from (payments on) derivatives for the three and nine months ended September 30, 2019 and 2018:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
(in millions)2019 2018 2019 2018
Net cash receipts from (payments on) derivatives:   
    
Oil derivatives$(21) $(46) $(72) $(245)
Natural gas derivatives14
 2
 15
 7
Total$(7) $(44) $(57) $(238)
        


18

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

2019

Unaudited


Commodity derivative contracts at September 30, 2017.contracts. The following table sets forth the Company’s outstanding derivative contracts at September 30, 2017.2019. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at September 30, 20172019 are expected to settle by December 31, 2019.

2021.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

Oil Price Swaps: (a)

  

 

 

 

 

 

 

 

 

 

 

2017:

  

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

 

 

9,370,080

 

9,370,080

 

 

Price per Bbl

 

 

 

 

 

 

$

51.33

$

51.33

 

2018:

  

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

8,180,629

 

7,546,170

 

7,064,318

 

6,676,007

 

29,467,124

 

 

Price per Bbl

$

51.54

$

51.45

$

51.36

$

51.26

$

51.41

 

2019:

  

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

5,314,000

 

5,090,000

 

4,897,000

 

4,721,000

 

20,022,000

 

 

Price per Bbl

$

52.54

$

52.52

$

52.54

$

52.55

$

52.54

Oil Basis Swaps: (b)

 

 

 

 

 

 

 

 

 

 

 

2017:

  

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

 

 

8,508,000

 

8,508,000

 

 

Price per Bbl

 

 

 

 

 

 

$

(0.74)

$

(0.74)

 

2018:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

7,936,000

 

7,521,000

 

6,961,000

 

6,684,000

 

29,102,000

 

 

Price per Bbl

$

(1.02)

$

(1.01)

$

(1.01)

$

(1.01)

$

(1.01)

 

2019:

  

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

4,581,000

 

4,428,000

 

4,262,000

 

4,139,000

 

17,410,000

 

 

Price per Bbl

$

(1.17)

$

(1.17)

$

(1.18)

$

(1.18)

$

(1.17)

Natural Gas Price Swaps: (c)

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

 

 

 

 

 

 

14,673,000

 

14,673,000

 

 

Price per MMBtu

 

 

 

 

 

 

$

3.10

$

3.10

 

2018:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

11,156,000

 

10,641,000

 

10,219,000

 

9,904,000

 

41,920,000

 

 

Price per MMBtu

$

3.06

$

3.05

$

3.05

$

3.04

$

3.05

 

2019:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

2,791,533

 

2,681,387

 

2,578,537

 

2,489,535

 

10,540,992

 

 

Price per MMBtu

$

2.86

$

2.85

$

2.85

$

2.85

$

2.85

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

(b) The basis differential price is between Midland – WTI and Cushing – WTI.

(c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

               
  2019 2020  
  
Fourth
Quarter
 First Quarter Second Quarter Third Quarter Fourth Quarter Total 2021
Oil Price Swaps – WTI: (a)
              
Volume (MBbl) 13,469
 12,517
 11,075
 10,067
 9,586
 43,245
 13,137
Price per Bbl $56.46
 $57.01
 $56.88
 $56.93
 $57.01
 $56.96
 $55.33
Oil Price Swaps – Brent: (b)
              
Volume (MBbl) 2,178
 1,456
 1,456
 1,472
 1,472
 5,856
 —
Price per Bbl $62.08
 $60.12
 $60.12
 $60.12
 $60.12
 $60.12
 $—
Oil Costless Collars: (a)              
Volume (MBbl) 1,058
 —
 —
 —
 —
 —
 —
Ceiling price per Bbl $62.95
 $—
 $—
 $—
 $—
 $—
 $—
Floor price per Bbl $55.43
 $—
 $—
 $—
 $—
 $—
 $—
Oil Basis Swaps: (c)              
Volume (MBbl) 16,053
 14,651
 10,647
 10,580
 10,120
 45,998
 14,600
Price per Bbl $(2.19) $(0.46) $(0.65) $(0.66) $(0.71) $(0.60) $0.57
Natural Gas Price Swaps – Henry Hub: (d)
              
Volume (BBtu) 37,750
 35,024
 32,313
 30,038
 28,498
 125,873
 36,500
Price per MMBtu $2.51
 $2.46
 $2.46
 $2.47
 $2.47
 $2.47
 $2.52
Natural Gas Basis Swaps – Henry Hub/El Paso Permian: (e)
              
Volume (BBtu) 28,820
 25,770
 23,960
 22,080
 21,770
 93,580
 36,500
Price per MMBtu $(0.76) $(1.06) $(1.07) $(1.07) $(1.07) $(1.07) $(0.66)
Natural Gas Basis Swaps – Henry Hub/WAHA: (f)
              
Volume (BBtu) 9,200
 7,280
 7,280
 7,360
 7,360
 29,280
 10,950
Price per MMBtu $(0.77) $(1.10) $(1.10) $(1.10) $(1.10) $(1.10) $(0.66)
               
               
(a) These oil derivative contracts are settled based on the New York Mercantile Exchange (“NYMEX”) – West Texas Intermediate (“WTI”) calendar-month average futures price.
(b) These oil derivative contracts are settled based on the Brent calendar-month average futures price.
(c) The basis differential price is between Midland – WTI and Cushing – WTI. The majority of these contracts are settled on a calendar-month basis, while certain contracts assumed in connection with the RSP acquisition are settled on a trading-month basis.
(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
At September 2017,30, 2019, the Company elected to enter into an “Investment Grade Period” under the Credit Facility, as defined below, which had the effecta net asset position of releasing all collateral formerly securing the Credit Facility. Additionally,$307 million as a result of outstanding derivative contracts, which are reflected in the Company’s Investment Grade Period election alongaccompanying balance sheets. The Company assessed this balance for concentration risk and noted balances of approximately $79 million, $72 million and $36 million with amendments to certain ISDA Agreements with the Company’s derivative counterparties, the Company’s derivatives are no longer secured. See Note 8 for additional information regarding the Credit Facility.

J.P. Morgan Chase Bank, Wells Fargo Bank N.A. and PNC Bank N.A., respectively.

17


19

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

2019

Unaudited


Note 8. Debt 

The Company’s debt consisted of the following at September 30, 20172019 and December 31, 2016:

2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

 

December 31,

(in millions)

 

 

2017

 

 

2016

 

 

 

 

 

 

 

 

 

Credit facility

 

$

368

 

$

-

5.5% unsecured senior notes due 2022

 

  

-

 

  

600

5.5% unsecured senior notes due 2023

 

  

-

 

  

1,550

4.375% unsecured senior notes due 2025

 

  

600

 

  

600

3.75% unsecured senior notes due 2027

 

  

1,000

 

  

-

4.875% unsecured senior notes due 2047

 

  

800

 

  

-

Unamortized original issue premium (discount), net

 

  

(6)

 

  

22

Senior notes issuance costs, net

 

 

(24)

 

 

(31)

 

Less: current portion

 

  

-

 

  

-

 

 

Total long-term debt

 

$

2,738

 

$

2,741

 

 

 

 

 

 

 

 

 

(in millions)September 30,
2019		 December 31,
2018
Credit facility due 2022$395
 $242
4.375% unsecured senior notes due 2025 (a)600
 600
3.75% unsecured senior notes due 20271,000
 1,000
4.3% unsecured senior notes due 20281,000
 1,000
4.875% unsecured senior notes due 2047800
 800
4.85% unsecured senior notes due 2048600
 600
Unamortized original issue discount(10) (10)
Senior notes issuance costs, net(36) (38)
Less: current portion—
 —
Total long-term debt$4,349
 $4,194
 
(a) For each of the twelve-month periods beginning on January 15, 2020, 2021, 2022, 2023 and thereafter, these notes are
       callable at 103.281%, 102.188%, 101.094% and 100%, respectively.


Credit facility.The Company’s credit facility, as amended and restated (the “Credit Facility”),Credit Facility has a maturity date of May 9, 2022. At September 30, 2017,2019, the Company’s commitments from its bank group were $2.0 billion.

In April 2017,billion, of which $1.6 billion were unused commitments, net of letters of credit. During the Company amended the Credit Facility to extend the maturity date, increase the borrowing basethree and decrease unused lender commitments. The amendment also lowered the corporate ratings floor sufficient to automatically terminate an Investment Grade Period under the Credit Facility from (i) “Ba1” to “Ba2” for Moody’s Investors Service, Inc. (“Moody’s”) and (ii) “BB+” to “BB” for S&P Global Ratings (“S&P”).

The Company recorded a loss on extinguishment of debt of approximately $1 million during the nine months ended September 30, 2017 for2019, the proportional amount of unamortized deferred loan costs associated with banks that are no longer inweighted average interest rates on 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 oilwere 4.0 percent and natural gas properties and by a pledge of the equity interests in its subsidiaries.4.3 percent, respectively.  At September 30, 2017,2019, certain of the Company’s 100 percent owned subsidiaries arewere guarantors under the Credit Facility.

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

18

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

Unaudited

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

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

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

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

·restrictions on the payment of cash dividends.

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

In September 2017, the Company issued $1,800 million14, and rank equally in aggregate principal amountright 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, togetherpayments with the 3.75% Notes, the “Notes”). The 3.75% Notes were issued at a price equal to 99.636 percent of par, and the 4.875% Notes were issued at a price equal to 99.749 percent of par. The Company received net proceeds of approximately $1,777 million.

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

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

one another.

19

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

At September 30, 2017

Unaudited

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

 

 

 

 

 

 

 

 

 

 

 

 

(in millions)

 

 

Tender Offer

 

 

Extinguishment

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

Tender premium

 

$

36

 

$

-

 

$

36

Make-whole premium

 

  

-

 

  

25

 

  

25

Prepaid interest

 

  

-

 

  

2

 

  

2

Unamortized original issue premium

 

  

(11)

 

  

(8)

 

  

(19)

Unamortized deferred loan costs

 

  

12

 

  

9

 

  

21

 

 

Total loss on extinguishment of debt

 

$

37

 

$

28

 

$

65

 

 

 

 

 

 

 

 

 

 

 

 

At September 30, 2017,2019, 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 September 30, 2017 were as follows:

 

 

 

 

 

 

(in millions)

 

 

 

 

 

 

 

 

 

 

Remaining 2017

 

$

 

-

2018

 

 

 

-

2019

 

 

 

-

2020

 

 

 

-

2021

 

 

 

-

2022

 

 

 

368

Thereafter

 

 

 

2,400

 

Total

$

 

2,768

 

 

 

 

 

 

Interest expense. The following amounts have been incurred and charged to interest expense for the three and nine months ended September 30, 20172019 and 2016:

2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

(in millions)

(in millions)

 

2017

 

2016

 

2017

 

2016

Three Months Ended
September 30,		 Nine Months Ended
September 30,

 

 

 

 

 

 

 

 

 

 

(in millions)2019 2018 2019 2018

Cash payments for interest

  

$

73

 

$

109

  

$

138

 

$

215

$57
 $16
 $166
 $76

Non-cash interest

Non-cash interest

 

 

1

 

 

3

  

 

5

 

 

7

2
 1
 5
 4

Net changes in accruals

Net changes in accruals

 

 

(35)

 

 

(59)

  

 

(25)

 

 

(60)

(7) 31
 (15) 28
Interest costs incurred52
 48
 156
 108
Less: capitalized interest(6) (2) (15) (5)
Total interest expense$46
 $46
 $141
 $103

Total interest expense

 

$

39

 

$

53

  

$

118

 

$

162

       

 

 

 

 

 

 

 

 

 

 

 

 



20

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

2019

Unaudited


Note 9. Commitments and contingencies

Legal actions. The Company is a party to proceedings and claims incidental to its business. While manyAssessing 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 thesefactors, 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, ifloss for any ultimately incurred with respectother litigation matters and claims that are reasonably possible to any such proceedings or claimsoccur will not have a material adverse effect on the Company’s consolidatedits 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 reservesestimated accruals as appropriate to reflect its assessment of the then current status of the matters.

appropriate.

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

Commitments.  The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including drilling commitments, water commitment agreements, throughput volume delivery commitments, fixed and variable power commitments, fixed assetsand commitment agreements and other commitments. The Company’s drilling rig commitments are considered leases under ASU 2016-02 and maintenance commitments.are included within the tables under the “Leases” section below. The following table summarizes the Company’s commitments at September 30, 2017:

2019:

 

 

 

 

(in millions)

(in millions)

 

 

 

 

 

 

 

 

Remaining 2017

 

$

10

2018

 

 

40

2019

 

 

59

Remaining 2019$12

2020

2020

 

 

32

62

2021

2021

 

 

31

75

2022

2022

 

 

26

38
202335
202436

Thereafter

Thereafter

 

 

88

102
Total$360

Total

$

286

 

 

 

 

 


21

At September 30, 2019, the Company’s delivery commitments covered the following gross volumes of oil and natural gas:
 
Oil
(MMBbl)
 
Natural Gas
(MMcf)
Remaining 20197
 560
202049
 1,633
202151
 14,112
202259
 16,425
202351
 16,425
202447
 16,470
Thereafter113
 32,850
Total377
 98,475
    

Operating leases.Leases. The Company leases vehicles,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.

21
Table of Contents
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

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 facilitiesspace, office equipment, drilling rigs, and field equipment. The Company did not elect this practical expedient for vehicle leases.
The following table provides supplemental consolidated balance sheet information related to leases at September 30, 2019:
(in millions)ClassificationSeptember 30, 2019
Assets  
Operating lease right-of-use assetsOther property and equipment, net$16
Finance lease right-of-use assetsOther property and equipment, net17
Total lease right-of-use assets (a) $33
   
Liabilities  
Current:  
Operating Other current liabilities$8
Finance Other current liabilities6
Noncurrent:  
Operating Asset retirement obligations and other long-term liabilities11
Finance Asset retirement obligations and other long-term liabilities11
Total lease liabilities (a) $36
   
(a) Total lease right-of-use assets and lease liabilities are gross amounts, and a portion of these costs will be reimbursed by other working interest owners.

As of September 30, 2019, the Company had additional operating leases that have not yet commenced. Future undiscounted lease payments of $15 million and 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 three and nine months ended September 30, 2019:
(in millions)ClassificationThree Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Operating lease costGeneral and administrative$2
 $6
Finance lease costDepreciation, depletion, and amortization (a)2
 6
Total lease cost $4
 $12
     
(a) Interest on lease liabilities related to finance leases was immaterial during the three and nine months ended September 30, 2019.

The Company’s short-term leases are primarily composed of drilling rigs and certain field equipment. During the three and nine months ended September 30, 2019, the Company’s gross lease costs related to its short-term leases were $64 million and $248 million, respectively, of which $43 million and $174 million, respectively, 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.

22
Table of Contents
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

The following table summarizes supplemental cash flow information related to leases for the nine months ended September 30, 2019:
(in millions)Nine Months Ended September 30, 2019
Cash paid for amounts included in measurement of lease liabilities: 
Operating cash flows from operating leases$6
Financing cash flows from finance leases$6
Right-of-use assets obtained in exchange for lease obligations: 
Operating leases$3
Finance leases$7
  

The following table provides lease terms and discount rates related to leases at September 30, 2019:
September 30, 2019
Weighted average remaining lease term (years):
Operating leases3.4
Finance leases2.9
Weighted average discount rate (a):
Operating leases4.7%
Finance leases4.3%
(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 September 30, 2019:
(in millions)Operating Leases Finance Leases
Remaining 2019$2
 $2
20208
 7
20217
 5
20222
 3
2023—
 1
Thereafter2
 —
Total lease payments21
 18
Less: interest(2) (1)
Present value of lease liabilities$19
 $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. LeaseTopic 840 for all periods that continue to be in accordance with Topic 840. As such, the Company included the future minimum lease commitments table below as of December 31, 2018. In addition, lease payments associated with these operating leases were approximately $2$3 million and $9 million for eachthe three and nine months ended September 30, 2018, respectively. 

23
Table of Contents
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

Future minimum lease commitments under non-cancellable leases at December 31, 2018 were as follows:
(in millions) 
2019$14
202012
202110
20223
2023—
Thereafter1
Total$40
  

Note 10. Income taxes
The Company’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items. For the three months ended September 30, 20172019 and 2016 and approximately $72018, the Company recorded income tax expense of $222 million and $6an income tax benefit of $69 million, respectively. The change in the income tax provision was primarily due to the pre-tax income for the three months ended September 30, 2019 as compared to the pre-tax loss for the three months ended September 30, 2018. For the nine months ended September 30, 2019 and 2018, the Company recorded an income tax benefit of $25 million and an income tax expense of $225 million, respectively. The change in the income tax provision was primarily due to the pre-tax loss for the nine months ended September 30, 2017 and 2016, respectively.

Future minimum lease commitments under non-cancellable operating leases at 2019 as compared to the pre-tax income for the nine months ended September 30, 2017 were as follows:

2018.

 

 

 

 

 

(in millions)

 

 

 

 

 

 

 

 

Remaining 2017

 

$

2

2018

 

 

9

2019

 

 

7

2020

 

 

6

2021

 

 

4

2022

 

 

-

Thereafter

 

 

1

 

Total

$

29

 

 

 

 

 

Note 10. Income taxes

The effective income tax rates were 36.729 percent and 37.326 percent for the three months ended September 30, 20172019 and 2016,2018, respectively, and 36.610 percent and 36.923 percent for the nine months ended September 30, 20172019 and 2016,2018, respectively. Total

At the end of each interim period, we apply a forecasted annualized effective tax rate to the current period income or loss before income taxes, which can produce interim effective tax expenserate fluctuations. The difference between the Company’s effective tax rates for the three and nine months ended September 30, 2017 differed from amounts computed by applying2019 as compared to the United States federal statutory tax rates to pre-tax incomesame periods in 2018 was primarily due to state income taxesthe research and development credit, net of unrecognized tax benefits, recorded in 2019, and the impact of permanent differences between book and taxable income.income (loss). The lower effective tax rate during 2019 was partially the result of the permanent differences primarily related to the discrete, non-deductible goodwill impairment of $81 million recognized as a result of the pending 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 net operating loss apportioned carryforwards for corporations. As a result of this law change, the Company recorded a discrete incomean estimated deferred state tax benefit of approximately $6 million for the nine months ended September 30, 20172019.
The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based upon the technical merits of the position. At December 31, 2018, the Company had cumulative unrecognized tax benefits of approximately $63 million, primarily related to excessresearch and development credits. As of September 30, 2019, the Company estimated an increase in cumulative unrecognized tax benefits on stock-based awards, which are recordedfor the 2019 tax year of approximately $17 million. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the income tax provision pursuantperiod recognized. The timing as to ASU No. 2016-09, which was adopted on January 1, 2017. Total incomewhen the Company will substantially resolve the uncertainties associated with the unrecognized tax benefit for the three months ended September 30, 2017 and the three and nine months ended September 30, 2016 differed from amounts computed by applying the United States federal statutory tax rates to pre-tax loss primarily due to state income taxes, partially offset by the impact of permanent differences between book and taxable loss.is uncertain.

Note 11.Related party transactions

The Company paid royalties on certain properties to a partnership in which a director of the Company is the general partner and owns a 3.5 percent limited partnership interest. These payments were reported in the Company’s consolidated statements of operations and totaled approximately $1$2 million for each ofboth the three months ended September 30, 20172019 and 20162018, and approximately $5$6 million and $3 million for both the nine months ended September 30, 20172019 and 2016,2018.
At September 30, 2019, the Company had ownership interests in entities that operate and manage various infrastructure assets and accounts for these investments using the equity method. The Company made payments to these entities of $9 million and $24 million for the three and nine months ended September 30, 2019, respectively.

22


24

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

2019

Unaudited


Note 12.Earnings per share

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

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

The following table reconciles the Company’s earnings (loss) from operations and earnings (loss) attributable to common stockholders to the basic and diluted earnings (loss) used to determine the Company’s earnings (loss) per share amounts for the three and nine months ended September 30, 20172019 and 2016, respectively,2018 under the two-class method:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

Nine Months Ended

 

 

 

 

September 30,

 

September 30,

(in millions)

 

2017

 

2016

 

2017

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) as reported

 

$

(113)

 

$

(51)

 

$

689

 

$

(1,337)

Participating basic earnings (a)

 

 

-

 

 

-

 

 

(5)

 

 

-

 

Basic earnings attributable to common stockholders

 

 

(113)

 

 

(51)

 

 

684

 

 

(1,337)

Reallocation of participating earnings

 

 

-

 

 

-

 

 

-

 

 

-

 

Diluted earnings attributable to common stockholders

 

$

(113)

 

$

(51)

 

$

684

 

$

(1,337)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

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

23

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

Unaudited


Three Months Ended
September 30,		 Nine Months Ended
September 30,
(in millions)2019
2018 2019 2018
Net income (loss) as reported$558

$(199) $(234) $773
Participating basic earnings (a)(4)
—
 (1) (6)
Basic earnings (loss) attributable to common stockholders554

(199) (235) 767
Reallocation of participating earnings—

—
 —
 —
Diluted earnings (loss) attributable to common stockholders$554

$(199) $(235) $767
        
(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 three and nine months ended September 30, 20172019 and 2016:

2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

Three Months Ended
September 30,		 Nine Months Ended
September 30,

(in thousands)

(in thousands)

 

2017

 

2016

 

2017

 

2016

2019
2018 2019 2018
Weighted average common shares outstanding:


    
Basic199,448

188,953
 199,272
 161,605
Dilutive performance units6

—
 —
 342
Diluted199,454

188,953
 199,272
 161,947

 

 

 

 

 

 

 

 

 

 

       

Weighted average common shares outstanding:

  

 

 

 

  

 

 

 

Basic

  

147,557

 

135,454

 

147,233

 

131,417

 

Dilutive common stock options

  

-

 

-

 

4

 

-

 

Dilutive performance units

  

-

 

-

 

549

 

-

Diluted

  

147,557

 

135,454

  

147,786

 

131,417

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30,

 

September 30,

Three Months Ended
September 30,		 Nine Months Ended
September 30,

(in thousands)

(in thousands)

 

2017

 

2016

 

2017

 

2016

2019 2018 2019 2018
Number of antidilutive units:       
Performance units324
 359
 431
 110

 

 

 

 

 

 

 

 

 

       

Number of antidilutive units:

  

 

 

 

  

 

 

 

Antidilutive performance units

  

-

 

-

 

107

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


Performance unit awards. The number of shares of common stock that will ultimately be issued for performance units will be determined by a combination of (i) comparing the Company’s total shareholderstockholder return relative to the total shareholderstockholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholderstockholder return at the end of the performance period. The performance period is 36 months.on these awards can range from three to five years. The actual payout of shares will be between zero0 and 300 percent.

See Note 5 for additional information on performance unit awards.

24


25

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

2019

Unaudited


Note 13. Subsidiary guarantors

At Stockholders' equity

Common stock dividends. The Company paid dividends of $25 million, or $0.125 per share, and $75 million, or $0.375 per share, during the three and nine months ended September 30, 2017,2019, respectively.
Note 14.Subsidiary guarantors
At September 30, 2019, certain of the Company’s 100 percent owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be released in certain customary circumstances including (i) in connection with any sale, exchange or other disposition, whether by merger, consolidation or otherwise, of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Company to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee.

See Note 8 for a summary of the Company’s senior notes. In accordance with practices accepted by the United States Securities and Exchange Commission,SEC, the Company has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. In addition, twocertain 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 suchThese entities is a VIE that was formed to effectuate a tax-free exchange of assets, and the other entity is aare 100 percent owned subsidiary that was recently acquired. These entitiessubsidiaries and are referred to as a “Subsidiary Non-Guarantors”Non-Guarantor” in the tables below.

The following condensed consolidating balance sheets at September 30, 20172019 and December 31, 2016,2018, condensed consolidating statements of operations for the three and nine months ended September 30, 20172019 and 2016 2018 and condensed consolidating statements of cash flows for the nine months ended September 30, 20172019 and 2016, 2018, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company.

25


26

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

Unaudited

2019
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Condensed Consolidating Balance Sheet

September 30, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

Subsidiary

 

Subsidiary

 

 

Consolidating

 

 

 

(in millions)

  

 

Issuer

  

Guarantors

Non-Guarantors

 

Entries

  

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ASSETS

  

 

 

  

 

 

 

 

 

  

 

 

  

 

 

Accounts receivable - related parties

  

$

8,903

 

$

(653)

 

$

-

 

$

(8,250)

 

$

-

Other current assets

  

 

14

 

 

515

 

 

6

 

 

-

 

 

535

Oil and natural gas properties, net

  

 

-

 

 

11,968

 

 

619

 

 

-

 

 

12,587

Property and equipment, net

  

 

-

 

 

232

 

 

-

 

 

-

 

 

232

Investment in subsidiaries

  

 

2,963

 

 

-

 

 

-

 

 

(2,963)

 

 

-

Other long-term assets

  

 

42

 

 

86

 

 

-

 

 

-

 

 

128

 

Total assets

  

$

11,922

  

$

12,148

 

$

625

  

$

(11,213)

  

$

13,482

 

 

  

 

 

  

 

 

 

 

 

  

 

 

  

 

 

LIABILITIES AND EQUITY

 

 

 

  

 

 

 

 

 

  

 

 

  

 

 

Accounts payable - related parties

  

$

(653)

 

$

8,290

 

$

613

 

$

(8,250)

 

$

-

Other current liabilities

  

 

50

 

 

756

 

 

4

 

 

-

 

 

810

Long-term debt

  

 

2,738

 

 

-

 

 

-

 

 

-

 

 

2,738

Other long-term liabilities

  

 

1,156

 

 

141

 

 

6

 

 

-

 

 

1,303

Equity

  

 

8,631

 

 

2,961

 

 

2

 

 

(2,963)

 

 

8,631

 

Total liabilities and equity

  

$

11,922

  

$

12,148

 

$

625

  

$

(11,213)

  

$

13,482

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unaudited

Condensed Consolidating Balance Sheet

December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in millions)

  

 

Issuer

  

 

Guarantors

 

 

Entries

  

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ASSETS

  

 

 

  

 

 

 

 

 

  

 

 

Accounts receivable - related parties

  

$

8,991

 

$

(336)

 

$

(8,655)

 

$

-

Other current assets

  

 

12

 

 

534

 

 

-

 

 

546

Oil and natural gas properties, net

  

 

-

 

 

11,086

 

 

-

 

 

11,086

Property and equipment, net

  

 

-

 

 

216

 

 

-

 

 

216

Investment in subsidiaries

  

 

1,989

 

 

-

 

 

(1,989)

 

 

-

Other long-term assets

  

 

11

 

 

260

 

 

-

 

 

271

 

Total assets

  

$

11,003

  

$

11,760

 

$

(10,644)

  

$

12,119

 

 

  

 

 

  

 

 

 

 

 

  

 

 

LIABILITIES AND EQUITY

 

 

 

  

 

 

 

 

 

  

 

 

Accounts payable - related parties

  

$

(336)

 

$

8,991

 

$

(8,655)

 

$

-

Other current liabilities

  

 

114

 

 

639

 

 

-

 

 

753

Long-term debt

  

 

2,741

 

 

-

 

 

-

 

 

2,741

Other long-term liabilities

  

 

861

 

 

141

 

 

-

 

 

1,002

Equity

  

 

7,623

 

 

1,989

 

 

(1,989)

 

 

7,623

 

Total liabilities and equity

  

$

11,003

  

$

11,760

 

$

(10,644)

  

$

12,119

 

 

 

 

 

 

 

 

 

 

 

 

 

 

26


Condensed Consolidating Balance Sheet
September 30, 2019
(in millions)
Parent
Issuer
 
Subsidiary
Guarantors
 
Subsidiary
Non-Guarantor
 
Consolidating
Entries
 Total
ASSETS         
Accounts receivable - related parties$18,133
 $—
 $—
 $(18,133) $—
Other current assets208
 1,809
 —
 —
 2,017
Oil and natural gas properties, net—
 21,004
 16
 —
 21,020
Property and equipment, net—
 408
 —
 —
 408
Investment in subsidiaries5,741
 —
 —
 (5,741) —
Goodwill—
 2,141
 —
 —
 2,141
Other long-term assets134
 412
 —
 —
 546
Total assets$24,216
 $25,774
 $16
 $(23,874) $26,132
          
LIABILITIES AND EQUITY         
Accounts payable - related parties$—
 $18,117
 $16
 $(18,133) $—
Other current liabilities86
 1,254
 —
 —
 1,340
Long-term debt4,349
 —
 —
 —
 4,349
Other long-term liabilities1,270
 662
 —
 —
 1,932
Equity18,511
 5,741
 —
 (5,741) 18,511
Total liabilities and equity$24,216
 $25,774
 $16
 $(23,874) $26,132
          
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 assets534
 875
 —
 —
 1,409
Oil and natural gas properties, net—
 21,988
 17
 —
 22,005
Property and equipment, net—
 308
 —
 —
 308
Investment in subsidiaries5,411
 —
 —
 (5,411) —
Goodwill—
 2,224
 —
 —
 2,224
Other long-term assets224
 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 liabilities70
 1,286
 —
 —
 1,356
Long-term debt4,194
 —
 —
 —
 4,194
Other long-term liabilities1,292
 684
 —
 —
 1,976
Equity18,768
 5,411
 —
 (5,411) 18,768
Total liabilities and equity$24,324
 $25,519
 $17
 $(23,566) $26,294
          


27

Table of Contents

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2017

Unaudited

2019
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in millions)

  

 

Issuer

 

 

Guarantors

 

 

Non-Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

    

 $  

-

 

 $  

619

 

 $  

8

 

 $  

-

 

 $  

627

Total operating costs and expenses

  

 

(207)

 

 

(491)

 

 

(6)

 

 

-

 

 

(704)

 

Income (loss) from operations

    

 

(207)

 

 

128

 

 

2

 

 

-

 

 

(77)

Interest expense

  

 

(39)

 

 

-

 

 

-

 

 

-

 

 

(39)

Loss on extinguishment of debt

    

 

(65)

 

 

-

 

 

-

 

 

-

 

 

(65)

Other, net

  

 

132

 

 

2

 

 

-

 

 

(132)

 

 

2

 

Income (loss) before income

    

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     taxes

 

 

(179)

 

 

130

 

 

2

 

 

(132)

 

 

(179)

Income tax benefit

    

 

66

 

 

-

 

 

-

 

 

-

 

 

66

 

Net income (loss)

  

$

(113)

 

$

130

 

$

2

 

$

(132)

 

$

(113)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unaudited






Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in millions)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

  

 $  

-

 

 $  

430

 

 $  

-

 

 $  

430

Total operating costs and expenses

  

 

41

 

 

(469)

 

 

-

 

 

(428)

 

Income (loss) from operations

  

 

41

 

 

(39)

 

 

-

 

 

2

Interest expense

  

 

(52)

 

 

(1)

 

 

-

 

 

(53)

Loss on extinguishment of debt

  

 

(28)

 

 

-

 

 

-

 

 

(28)

Other, net

  

 

(42)

 

 

(2)

 

 

42

 

 

(2)

 

Loss before income taxes

  

 

(81)

 

 

(42)

 

 

42

 

 

(81)

Income tax benefit

  

 

30

 

 

-

 

 

-

 

 

30

 

Net loss

  

 $  

(51)

 

 $  

(42)

 

 $  

42

 

 $  

(51)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

27


Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2019
(in millions)Parent
Issuer		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantor		 Consolidating
Entries		 Total
Total operating revenues$—
 $1,115
 $—
 $—
 $1,115
Total operating costs and expenses395
 (688) —
 —
 (293)
Income from operations395
 427
 —
 —
 822
Interest expense(46) —
 —
 —
 (46)
Other, net431
 4
 —
 (431) 4
Income before income taxes780
 431
 —
 (431) 780
Income tax expense(222) —
 —
 —
 (222)
Net income$558
 $431
 $—
 $(431) $558
          

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2018
(in millions)Parent
Issuer		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantor		 Consolidating
Entries		 Total
Total operating revenues$—
 $1,192
 $—
 $—
 $1,192
Total operating costs and expenses(626) (791) —
 —
 (1,417)
Income (loss) from operations(626) 401
 —
 —
 (225)
Interest expense(46) —
 —
 —
 (46)
Other, net404
 3
 —
 (404) 3
Income (loss) before income taxes(268) 404
 —
 (404) (268)
Income tax benefit69
 —
 —
 —
 69
Net income (loss)$(199) $404
 $—
 $(404) $(199)
          


28
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in millions)

  

 

Issuer

 

 

Guarantors

 

 

Non-Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

  

 $  

-

 

 $  

1,798

 

 $  

8

 

 $  

-

 

 $  

1,806

Total operating costs and expenses

  

 

288

 

 

(835)

 

 

(6)

 

 

-

 

 

(553)

 

Income from operations

  

 

288

 

 

963

 

 

2

 

 

-

 

 

1,253

Interest expense

  

 

(117)

 

 

(1)

 

 

-

 

 

-

 

 

(118)

Loss on extinguishment of debt

  

 

(66)

 

 

-

 

 

-

 

 

-

 

 

(66)

Other, net

  

 

982

 

 

18

 

 

-

 

 

(982)

 

 

18

 

Income before income taxes

  

 

1,087

 

 

980

 

 

2

 

 

(982)

 

 

1,087

Income tax expense

  

 

(398)

 

 

-

 

 

-

 

 

-

 

 

(398)

 

Net income

  

 $  

689

 

 $  

980

 

 $  

2

 

 $  

(982)

 

 $  

689

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 






Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in millions)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

    

 $  

-

 

 $  

1,110

 

 $  

-

 

 $  

1,110

Total operating costs and expenses

  

 

(177)

 

 

(2,853)

 

 

-

 

 

(3,030)

 

Loss from operations

    

 

(177)

 

 

(1,743)

 

 

-

 

 

(1,920)

Interest expense

  

 

(159)

 

 

(3)

 

 

-

 

 

(162)

Loss on extinguishment of debt

    

 

(28)

 

 

-

 

 

-

 

 

(28)

Other, net

  

 

(1,755)

 

 

(10)

 

 

1,756

 

 

(9)

 

Loss before income taxes

    

 

(2,119)

 

 

(1,756)

 

 

1,756

 

 

(2,119)

Income tax benefit

  

 

782

 

 

-

 

 

-

 

 

782

 

Net loss

    

 $  

(1,337)

 

 $  

(1,756)

 

 $  

1,756

 

 $  

(1,337)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table of Contents

28

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2019
(in millions)Parent
Issuer		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantor		 Consolidating
Entries		 Total
Total operating revenues$—
 $3,346
 $—
 $—
 $3,346
Total operating costs and expenses(448) (3,327) —
 —
 (3,775)
Income (loss) from operations(448) 19
 —
 —
 (429)
Interest expense(141) —
 —
 —
 (141)
Other, net330
 311
 —
 (330) 311
Income (loss) before income taxes(259) 330
 —
 (330) (259)
Income tax benefit25
 —
 —
 —
 25
Net income (loss)$(234) $330
 $—
 $(330) $(234)
          

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2018
(in millions)Parent
Issuer		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantor		 Consolidating
Entries		 Total
Total operating revenues$—
 $3,079
 $5
 $—
 $3,084
Total operating costs and expenses(794) (1,294) (3) —
 (2,091)
Income (loss) from operations(794) 1,785
 2
 —
 993
Interest expense(103) —
 —
 —
 (103)
Other, net1,895
 108
 —
 (1,895) 108
Income before income taxes998
 1,893
 2
 (1,895) 998
Income tax expense(225) —
 —
 —
 (225)
Net income$773
 $1,893
 $2
 $(1,895) $773
          



29
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

Subsidiary

Consolidating

 

 

(in millions)

  

 

Issuer

 

 

Guarantors

 

 

Non-Guarantors

 

 

Entries

  

 

Total

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash flows provided by operating activities

  

$

99

 

$

1,084

 

$

2

 

$

-

 

$

1,185

Net cash flows used in investing activities

 

 

-

 

 

(592)

 

 

(615)

 

 

-

 

 

(1,207)

Net cash flows provided by (used in) financing

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     activities

 

 

(99)

 

 

(545)

 

 

613

 

 

-

 

 

(31)

 

Net decrease in cash and cash equivalents

 

 

-

 

 

(53)

 

 

-

 

 

-

 

 

(53)

 

Cash and cash equivalents at beginning of period

  

 

-

 

 

53

 

 

-

 

 

-

 

 

53

 

Cash and cash equivalents at end of period

  

$

-

 

$

-

 

$

-

 

$

-

 

$

-

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table of Contents





Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Parent

 

 

Subsidiary

 

 

Consolidating

 

 

 

(in millions)

  

 

Issuer

 

 

Guarantors

 

 

Entries

  

 

Total

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Net cash flows provided by (used in) operating activities

 

$

(694)

 

$

1,713

 

$

-

   

$

1,019

Net cash flows used in investing activities

  

 

-

 

 

(783)

 

 

-

  

 

(783)

Net cash flows provided by financing activities

  

 

694

 

 

-

 

 

-

   

 

694

 

Net increase in cash and cash equivalents

  

 

-

 

 

930

 

 

-

 

 

930

 

Cash and cash equivalents at beginning of period

  

 

-

 

 

229

 

 

-

 

 

229

 

Cash and cash equivalents at end of period

  

$

-

 

$

1,159

 

$

-

 

$

1,159

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Concho Resources Inc.

29

Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2019
(in millions)Parent
Issuer		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantor		 Consolidating
Entries		 Total
Net cash flows provided by (used in) operating activities$(63) $2,130
 $—
 $—
 $2,067
Net cash flows used in investing activities—
 (2,020) —
 —
 (2,020)
Net cash flows provided by (used in) financing activities63
 (110) —
 —
 (47)
Net change in cash and cash equivalents—
 —
 —
 —
 —
Cash and cash equivalents at beginning of period—
 —
 —
 —
 —
Cash and cash equivalents at end of period$—
 $—
 $—
 $—
 $—
          

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2018
(in millions)Parent
Issuer		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantor		 Consolidating
Entries		 Total
Net cash flows provided by operating activities$386
 $1,475
 $—
 $—
 $1,861
Net cash flows used in investing activities—
 (1,422) —
 —
 (1,422)
Net cash flows used in financing activities(386) (29) —
 —
 (415)
Net increase in cash and cash equivalents—
 24
 —
 —
 24
Cash and cash equivalents at beginning of period—
 —
 —
 —
 —
Cash and cash equivalents at end of period$—
 $24
 $—
 $—
 $24
          


30

Table of Contents
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

Note 14. 15.Subsequent events

2019 dividends.On October 29, 2019, the Company’s board of directors approved a cash dividend of $0.125 per share for the fourth quarter of 2019 that is expected to be paid on December 20, 2019 to stockholders of record as of November 8, 2019.
New commodity derivative contracts.After September 30, 2017,2019, the Company entered into the following oil price swaps, oil basis swaps and natural gas price swapsderivative contracts to hedge additional amounts of the Company’s estimated future production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

 

 

 

 

  

 

 

 

 

 

 

 

 

 

Oil Price Swaps: (a)

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

 

 

846,000

 

846,000

 

 

Price per Bbl

 

 

 

 

 

 

$

51.29

$

51.29

 

2018:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

953,000

 

600,000

 

407,000

 

296,000

 

2,256,000

 

 

Price per Bbl

$

51.55

$

51.39

$

51.43

$

51.28

$

51.45

 

2019:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

1,035,000

 

1,046,500

 

828,000

 

828,000

 

3,737,500

 

 

Price per Bbl

$

51.25

$

51.25

$

51.14

$

51.14

$

51.20

Oil Basis Swaps: (b)

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

 

 

1,499,000

 

1,499,000

 

 

Price per Bbl

 

 

 

 

 

 

$

(0.12)

$

(0.12)

 

2018:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

540,000

 

546,000

 

276,000

 

276,000

 

1,638,000

 

 

Price per Bbl

$

(0.21)

$

(0.21)

$

(0.38)

$

(0.38)

$

(0.27)

 

2019:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

1,395,000

 

1,410,500

 

1,426,000

 

1,426,000

 

5,657,500

 

 

Price per Bbl

$

(0.68)

$

(0.68)

$

(0.68)

$

(0.68)

$

(0.68)

Natural Gas Price Swaps: (c)

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

 

 

 

 

 

 

3,660,000

 

3,660,000

 

 

Price per MMBtu

 

 

 

 

 

 

$

3.02

$

3.02

 

2018:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

5,400,000

 

5,460,000

 

4,600,000

 

4,600,000

 

20,060,000

 

 

Price per MMBtu

$

3.02

$

3.02

$

3.01

$

3.01

$

3.02

 

2019:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

1,800,000

 

1,820,000

 

1,840,000

 

1,840,000

 

7,300,000

 

 

Price per MMBtu

$

2.86

$

2.86

$

2.86

$

2.86

$

2.86

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price.

(b)

The basis differential price is between Midland – WTI and Cushing – WTI.

(c)

The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

   
  2021
Oil Price Swaps – WTI: (a)
  
Volume (MBbl) 4,380
Price per Bbl $51.21
Oil Basis Swaps: (b)  
Volume (MBbl) 2,190
Price per Bbl $0.84
   
   
(a) These 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.
   

30



31

Table of Contents
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2019
Unaudited

Note 15. 16.Supplementary information


Capitalized costs

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(in millions)

(in millions)

 

2017

 

2016

September 30,
2019		 December 31,
2018
Oil and natural gas properties:   
Proved$22,080
 $24,992
Unproved6,417
 6,714
Less: accumulated depletion(7,477) (9,701)
Net capitalized costs for oil and natural gas properties (a)$21,020
 $22,005

 

 

 

 

 

 

   

Oil and natural gas properties:

 

 

 

 

 

Proved

 

$

17,950

 

$

16,620

Unproved

 

2,804

 

1,856

Less: accumulated depletion

 

 

(8,167)

 

 

(7,390)

 

Net capitalized costs for oil and natural gas properties

 

 $  

12,587

 

 $  

11,086

 

 

 

 

 

 

 

 

 

 

 

 

(a) Excludes $930 million of net capitalized costs related to the New Mexico Shelf assets that were classified as held for sale as of September 30, 2019.(a) Excludes $930 million of net capitalized costs related to the New Mexico Shelf assets that were classified as held for sale as of September 30, 2019.


Costs incurred for oil and natural gas producing activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

 

September 30,

 

September 30,

(in millions)

 

2017

 

2016

 

2017

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs:

  

 

 

 

 

 

  

 

 

 

 

 

 

Proved

  

$

162

 

$

1

 

$

301

 

$

257

 

Unproved

  

 

472

 

 

14

 

 

865

 

 

172

Exploration

  

 

252

 

 

177

 

 

725

 

 

513

Development

  

 

175

 

 

97

 

 

478

 

 

287

 

Total costs incurred for oil and natural gas properties

  

$

1,061

 

$

289

  

$

2,369

 

$

1,229

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

31


Three Months Ended
September 30,		 Nine Months Ended
September 30,
(in millions)2019
2018 2019 2018
Property acquisition costs:


    
Proved$—

$4,126
 $—
 $4,126
Unproved20

3,578
 33
 3,596
Exploration (a)412

481
 1,309
 1,059
Development (a)258

280
 1,072
 653
Total costs incurred for oil and natural gas properties$690

$8,465
 $2,414
 $9,434
        
(a) Asset retirement obligations included in the Company's costs incurred for oil and natural gas producing activities were $13 million and $1 million for the three months ended September 30, 2019 and 2018, respectively, and $16 million and $2 million for the nine months ended September 30, 2019 and 2018, respectively. Asset retirement obligations for the three and nine months ended September 30, 2019 were primarily the result of revised estimated future abandonment costs.



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

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

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

Overview

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

areas.

Financial and Operating Performance

On July 19, 2018, we completed our acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”), which, among other things, impacted the comparability of our results of operations. Our financial and operating performance for the nine months ended September 30, 20172019 and 20162018 included the following highlights:

·

Net incomeloss was $689 million$234 million ($4.63(1.18) per diluted share) as compared to net lossincome of $1.3billion$773 million ($(10.18)4.74 per diluted share) for the first nine months of 2017ended September 30, 2019 and 2016,2018, respectively. The increasedecrease in net income was primarily due to:

•no recorded

$969 million in non-cash impairments of long-lived assets during the nine months ended September 30, 2017,2019;
$416 million decrease in gain on disposition of assets due to a $303 million gain during the nine months ended September 30, 2019 primarily due to the contribution of certain infrastructure assets in exchange for a cash distribution and an equity ownership interest in the entity in July 2019, as compared to $1.5 billiona gain of $719 million primarily related to certain acquisitions and divestitures during 2018, as discussed in non-cash impairment chargesNote 4 of the Condensed Notes to Consolidated Financial Statements; and
$398 million increase in 2016, depreciation, depletion and amortization expense, primarily attributabledue to propertiesthe increase in our New Mexico Shelf area;

•production and the increase in the depletion rate per Boe.

partially offset by:
$696348 million decrease in loss on derivatives during the nine months ended September 30, 2019 as compared to 2018;
$262 million increase in oil and natural gas revenues as a result of a 2833 percent increase in production, and a 28partially offset by an 18 percent increasedecrease in commodity price realizations per Boe (excluding(excluding the effects of derivative activities);

•gain on disposition of assets, net increased $558

$250 million change in income taxes due to a gain of approximately $667$25 million tax benefit during the nine months ended September 30, 2017 primarily due to our disposition of Alpha Crude Connector, LLC (“ACC”),2019, as compared to a gain of approximately $109$225 million tax expense during 2016 primarily attributable to our Northern Delaware Basin divestiture2018; and
$203 million increase in February 2016;

•$465 million change in (gain) loss on derivatives due to a $289 million gain on derivatives other income during the nine months ended September 30, 2017, as compared to a $176 million loss on derivatives during 2016; and 

•$42 million decrease in depreciation, depletion and amortization expense,2019, primarily due to a decreasethe gain of $289 million on the sale of our ownership interest in the depletion ratesubsidiary of our equity method investment, Oryx Southern Delaware Holdings, LLC (“Oryx”).

Average daily sales volumes of 329 MBoe per Boe period over period, partially offset by an increase in production;

partially offset by:

•$1.2 billion change in our income tax provision due to income before income taxesday during the nine months ended September 30, 2017,2019 increased 33 percent as compared to a loss before income taxes during 2016;

32

•$53 million increase in production expense, primarily due to increased production associated with our wells successfully drilled and completed in 2016 and 2017; and

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

·Average daily sales volumes of 186,449 Boe248 MBoe per day during the first nine months of 2017 increased 28 percent as compared to 145,868 Boe per day during 2016.

·same period in 2018.

Net cash provided by operating activities increased by approximately $166$206 million to $1,185$2,067 million for the first nine months of 2017,ended September 30, 2019, as compared to $1,019 million in$1,861 million for the first nine months of 2016,ended September 30, 2018, primarily due to an increase in oil and natural gas revenues and decreased cash interest expense, partially offset by (i) a decrease inchanges related to cash settlements on derivatives, (ii) increased production expense, (iii) increased production tax expense and (iv) changes related to cash income taxes.

·Cash decreased by approximately $53 million during the first nine months of 2017 primarily as a result of cash paid to tender and extinguish our 5.5% Notes, as defined below, and cash paid for the Midland Basin and Northern Delaware Basin acquisitions, partially offset by proceeds from the issuance of the Notes, as defined below,increased 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. Commodity prices may fluctuate widely in response to (i) relatively minor changes in the supply of and demand for oil natural gas and natural gas, liquids, (ii) market uncertainty and (iii) a variety of additional factors that are beyond our control. Factors that may impact future commodity prices, including the price of oil natural gas and natural gas, liquids, include but are not limited to:

·continuing

the overall global demand for oil and natural gas;
the domestic and foreign supply of oil, natural gas and natural gas liquids;
the overall North American oil and natural gas supply and demand fundamentals, including:
the U.S. economy,
weather conditions, and
liquefied natural gas (“LNG”) deliveries to and exports from the United States;
economic uncertaintyconditions worldwide;

·

the proximity, capacity, cost and availability of pipelines and other transportation facilities, as well as the availability of commodity processing, gathering and refining capacity;
risks related to the concentration of our operations in the Permian Basin of West Texas and Southeast New Mexico and the level of commodity inventory in the Permian Basin;
the quality of the oil we produce;
the level of global crude oil, crude oil products and LNG inventories;
volatility and trading patterns in the commodity-futures markets;
political and economic developments in oil and natural gas producing regions, including Africa, South America and the Middle East;

·

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

·

technological advances affecting energy consumption and energy supply;

·

the effect of energy conservation efforts;
additional restrictions on the exploration, development and production of oil, natural gas and natural gas liquids so as to materially reduce emissions of carbon dioxide and methane greenhouse gases;
political and economic events that directly or indirectly impact the relative strength or weakness of the U.S. dollar, on which oil prices are benchmarked globally, against foreign currencies;
domestic and foreign governmental regulations, including limits on the United States’ ability to export crude oil, and taxation;

·

the level of global inventories;

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

·risks relatedpersonnel needed for us 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 quality of theproduce oil we produce;

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

·the domesticincluding rigs, crews, sand, water and foreign supply of oil, natural gaswater disposal; and natural gas liquids;

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

·the effect of energy conservation efforts;

·

the price, availability and availabilityacceptance of alternative fuels; and

fuels.

33

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

•the United States economy,

•weather conditions, and

•liquefied natural gas deliveries to and exports from the United States.

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 7 and 1415 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commodity derivative positions at September 30, 20172019 and additional derivative contracts entered into subsequent to September 30, 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 the comparable periods of 2017 measured against 2016.


The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three and nine months ended September 30, 20172019 and 2016,2018, as well as the high and low NYMEX prices for the same periods:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

  

 

 

 

September 30,

 

September 30,

 

 

 

 

2017

 

2016

 

2017

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average NYMEX prices:

  

 

 

 

 

 

  

 

 

 

 

 

 

Oil (Bbl)

  

$

48.12

 

$

45.03

  

$

49.45

 

$

41.45

 

Natural gas (MMBtu)

  

$

2.95

 

$

2.80

  

$

3.06

 

$

2.35

 

 

 

  

 

 

 

 

 

  

 

 

 

 

 

High and Low NYMEX prices:

  

 

 

 

 

 

  

 

 

 

 

 

 

Oil (Bbl):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

High

  

$

52.22

 

$

48.99

  

$

54.45

 

$

51.23

 

 

Low

  

$

44.23

 

$

39.51

  

$

42.53

 

$

26.21

 

Natural gas (MMBtu):

  

 

 

 

 

 

  

 

 

 

 

 

 

 

High

  

$

3.15

 

$

3.06

  

$

3.72

 

$

3.06

 

 

Low

  

$

2.77

 

$

2.55

  

$

2.56

 

$

1.64

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

  

 

 

 

 

 

 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
Average NYMEX prices:       
Oil (Bbl)$56.33
 $69.60
 $57.03
 $66.83
Natural gas (MMBtu)$2.33
 $2.87
 $2.57
 $2.85
        
High and Low NYMEX prices:       
Oil (Bbl):       
High$62.90
 $74.15
 $66.30
 $74.15
Low$51.09
 $65.01
 $45.41
 $59.19
Natural gas (MMBtu):       
High$2.68
 $3.08
 $3.59
 $3.63
Low$2.07
 $2.72
 $2.07
 $2.55
        
Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $54.15$56.66 and $49.29$52.45 per Bbl and $3.01$2.45 and $2.75$2.21 per MMBtu, respectively, during the period fromOctober 1, 20172019to October 30, 2017.28, 2019. At October 30, 2017,28, 2019, the NYMEX oil price and NYMEX natural gas price were $54.15$55.81 per Bbl and $2.97$2.45 per MMBtu, respectively.

Historically, and during the three and nine months ended September 30, 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 $25.04$16.99 per Bbl and $17.82$34.82 per Bbl during the three months ended September 30, 20172019 and 2016,2018, respectively, and $23.74$20.43 per Bbl and $16.82$30.73 per Bbl during the nine months ended September 30, 20172019 and 2016,2018, respectively.

34

Recent Events

Senior notes. In September 2017, we issued $1,800 million in aggregate principal amount


2019 dividends. On October 29, 2019, our board of unsecured senior notes, consistingdirectors approved a cash dividend of $1,000 million in aggregate principal amount$0.125 per share for the fourth quarter of 3.75% unsecured senior notes due 2027 (the “3.75% Notes”) and $800 million in aggregate principal amount2019 that is expected to be paid on December 20, 2019 to stockholders of 4.875% unsecured senior notes due 2047 (the “4.875% Notes” and, together with the 3.75% Notes, the “Notes”). We used the net proceedsrecord as of approximately $1,777 million, together withNovember 8, 2019. Total cash on hand and borrowings under the Credit Facility, as defined below, to funddividends, including the cash tender offer (the “Tender Offer”) anddividends on unvested restricted stock awards, paid to our stockholders during 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 during each of the three and nine months ended September 30, 2017. See Note 8 of the Condensed Notes2019 were $75 million.
New Mexico Shelf divestiture. On August 29, 2019, we entered into a definitive agreement to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regardingsell our senior notes.

Investment grade period. In September 2017, we elected to enter into an “Investment Grade Period” under the amended and restated credit facility (the “Credit Facility”), which had the effect of releasing all collateral formerly securing the Credit Facility. If the Investment Grade Period under the Credit Facility terminates (whether automatically due to a downgrade of our credit ratings below certain thresholds or by our election), the Credit Facility will once again be secured by a first lien on substantially all of our oil and natural gas properties and by a pledge of the equity interests in our subsidiaries. Additionally, as a result of our Investment Grade Period election along with amendments to certain International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our derivative counterparties, our derivatives are no longer secured.

Midland Basin acquisition.In July 2017, we completed an acquisitionassets in the Midland Basin. As considerationNew Mexico Shelf for the acquisition, we paid approximately $595cash proceeds of $925 million, subject to customary closing and post-closing adjustments. This transaction is expected to close in cash. The acquisitionNovember 2019 and is subject to customary post-closing adjustments. Concurrent with the acquisition, we entered into a transaction structured as a reverse like-kind exchange in accordance with Section 1031 of the Internal Revenue Code of 1986. Seeterms and conditions. Refer to Note 4 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding the New Mexico Shelf divestiture. We plan to use the proceeds from this transaction.

divestiture to repay the outstanding borrowings under our credit facility, as amended and restated ("Credit Facility"), and initiate the share repurchase program, as discussed below.

35

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. We intend to use a portion of the proceeds from the New Mexico Shelf divestiture, which is expected to close in November 2019, to initiate share repurchases in the fourth quarter of 2019.
Joint venture. In July 2019, we contributed certain water infrastructure assets primarily in Eddy County, New Mexico to Solaris Midstream Holdings, LLC (“Solaris”) in exchange for a cash distribution and a 20 percent equity ownership interest. Solaris owns and operates produced water gathering, transportation, disposal, recycling and storage infrastructure assets in the Permian Basin. In conjunction with the transaction, we entered into a water gathering and disposal agreement with Solaris.


Derivative Financial Instruments

Derivative financial instrument exposure.At September 30, 2017,2019, the fair value of our financial derivatives was a net liability asset of $11$307 million. Under the terms of our financial derivative instruments, we do not have exposure to potential “margin calls” on our financial derivative instruments. We currently have no reason to believe that our counterparties to these commodity derivative contracts are not financially viable. The terms of our Credit Facility do not allow us to offset amounts we may owe a lender against amounts we may be owed related to our derivative financial instruments with such party. In
New commodity derivative contracts.After September 2017,30, 2019, we electedentered into derivative contracts to enter into an Investment Grade Period under the Credit Facility, which had the effecthedge additional amounts of releasing all collateral formerly securing the Credit Facility and derivative obligations. Seeestimated future production. Refer to Note 815 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our Credit Facility.

Newthese commodity derivative contracts.After September 30, 2017, we entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts of our estimated future production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

 

 

 

 

  

 

 

 

 

 

 

 

 

 

Oil Price Swaps: (a)

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

 

 

846,000

 

846,000

 

 

Price per Bbl

 

 

 

 

 

 

$

51.29

$

51.29

 

2018:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

953,000

 

600,000

 

407,000

 

296,000

 

2,256,000

 

 

Price per Bbl

$

51.55

$

51.39

$

51.43

$

51.28

$

51.45

 

2019:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

1,035,000

 

1,046,500

 

828,000

 

828,000

 

3,737,500

 

 

Price per Bbl

$

51.25

$

51.25

$

51.14

$

51.14

$

51.20

Oil Basis Swaps: (b)

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

 

 

 

 

 

 

1,499,000

 

1,499,000

 

 

Price per Bbl

 

 

 

 

 

 

$

(0.12)

$

(0.12)

 

2018:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

540,000

 

546,000

 

276,000

 

276,000

 

1,638,000

 

 

Price per Bbl

$

(0.21)

$

(0.21)

$

(0.38)

$

(0.38)

$

(0.27)

 

2019:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbl)

 

1,395,000

 

1,410,500

 

1,426,000

 

1,426,000

 

5,657,500

 

 

Price per Bbl

$

(0.68)

$

(0.68)

$

(0.68)

$

(0.68)

$

(0.68)

Natural Gas Price Swaps: (c)

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

 

 

 

 

 

 

3,660,000

 

3,660,000

 

 

Price per MMBtu

 

 

 

 

 

 

$

3.02

$

3.02

 

2018:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

5,400,000

 

5,460,000

 

4,600,000

 

4,600,000

 

20,060,000

 

 

Price per MMBtu

$

3.02

$

3.02

$

3.01

$

3.01

$

3.02

 

2019:

 

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

1,800,000

 

1,820,000

 

1,840,000

 

1,840,000

 

7,300,000

 

 

Price per MMBtu

$

2.86

$

2.86

$

2.86

$

2.86

$

2.86

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

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

 

(b)

The basis differential price is between Midland – WTI and Cushing – WTI.

(c)

The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

36


Results of Operations

The following table sets forth summary information concerning our production and operating data for the three and nine months ended September 30, 20172019 and 2016. 2018. The actual historical data in this table excludes results from our acquisition from 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 our acquisitions orand divestitures, the historical information presented below should not be interpreted as being indicative of future results.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

  

 

 

 

 

  

September 30,

 

September 30,

 

 

 

 

 

 

2017

 

2016

 

2017

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and operating data:

 

 

 

 

 

 

 

 

 

 

 

 

 

Average daily production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbl)

  

 

119,565

 

 

91,120

 

 

115,484

 

 

89,854

 

 

Natural gas (Mcf)

  

 

441,587

 

 

370,609

 

 

425,791

 

 

336,084

 

 

Total (Boe)

  

 

193,163

 

 

152,888

 

 

186,449

 

 

145,868

 

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 Average prices per unit:

  

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, without derivatives (Bbl)

  

$

45.29

 

$

41.52

 

$

46.34

 

$

37.75

 

 

Oil, with derivatives (Bbl) (a)

  

$

47.81

 

$

59.87

 

$

50.45

 

$

60.74

 

 

Natural gas, without derivatives (Mcf)

  

$

3.18

 

$

2.42

 

$

2.96

 

$

1.97

 

 

Natural gas, with derivatives (Mcf) (a)

  

$

3.22

 

$

2.46

 

$

2.94

 

$

2.14

 

 

Total, without derivatives (Boe)

  

$

35.29

 

$

30.61

 

$

35.47

 

$

27.78

 

 

Total, with derivatives (Boe) (a)

  

$

36.96

 

$

41.65

 

$

37.95

 

$

42.35

 

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

Operating costs and expenses per Boe:

  

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas production

  

$

5.99

 

$

4.98

 

$

5.76

 

$

6.00

 

 

Production and ad valorem taxes

  

$

2.70

 

$

2.38

 

$

2.75

 

$

2.23

 

 

Depreciation, depletion and amortization

  

$

16.00

 

$

21.27

 

$

16.66

 

$

22.27

 

 

General and administrative

  

$

3.60

 

$

3.80

 

$

3.56

 

$

4.02

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

  

 

 

  

September 30,

 

September 30,

 

 

(in millions)

 

2017

 

2016

 

2017

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash receipts from (payments on) derivatives:

  

 

 

 

 

 

 

 

 

Oil derivatives

 

$

28

 

$

154

 

$

129

 

$

566

 

 

 

Natural gas derivatives

 

 

2

 

 

1

 

 

(3)

 

 

16

 

 

 

 

Total

 

$

30

  

$

155

  

$

126

  

$

582

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

37

 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
Production and operating data:       
Net production volumes:       
Oil (MBbl)18,940
 16,979
 56,602
 42,947
Natural gas (MMcf)68,411
 56,348
 199,284
 148,633
Total (MBoe)30,342
 26,370
 89,816
 67,719
        
Average daily production volumes:       
Oil (Bbl)205,870
 184,554
 207,333
 157,315
Natural gas (Mcf)743,598
 612,478
 729,978
 544,443
Total (Boe)329,803
 286,634
 328,996
 248,056
        
Average prices per unit: (a)       
Oil, without derivatives (Bbl)$54.01
 $56.38
 $53.13
 $59.25
Oil, with derivatives (Bbl) (b)$52.84
 $53.67
 $51.85
 $53.55
Natural gas, without derivatives (Mcf)$1.34
 $4.18
 $1.70
 $3.63
Natural gas, with derivatives (Mcf) (b)$1.54
 $4.21
 $1.77
 $3.67
Total, without derivatives (Boe)$36.74
 $45.23
 $37.25
 $45.54
Total, with derivatives (Boe) (b)$36.46
 $43.56
 $36.60
 $42.02
        
Operating costs and expenses per Boe: (a)       
Oil and natural gas production$6.26
 $5.93
 $6.14
 $6.15
Production and ad valorem taxes$2.79
 $3.37
 $2.84
 $3.38
Gathering, processing and transportation$0.82
 $0.60
 $0.81
 $0.53
Depreciation, depletion and amortization$16.07
 $15.43
 $15.93
 $15.27
General and administrative$2.50
 $3.13
 $2.82
 $3.26
        

(a)Per unit and per Boe amounts calculated using dollars and volumes rounded to thousands.
  
(b)Includes the effect of net cash receipts from (payments on) derivatives:
         
  Three Months Ended
September 30,		 Nine Months Ended
September 30,
 (in millions)2019 2018 2019 2018
 Net cash receipts from (payments on) derivatives:       
 Oil derivatives$(21) $(46) $(72) $(245)
 Natural gas derivatives14
 2
 15
 7
 Total$(7) $(44) $(57) $(238)
         
         
 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.
         
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016


Oil and natural gas revenues.  Revenue from oil and natural gas operations was$627 $1,115 million for the three months ended September 30, 20172019, a decrease of $77 million (6 percent) from $1,192 million for 2018. The decrease was primarily due to the decrease in oil and natural gas prices (excluding the effects of derivative activities), partially offset by the increase in oil and natural gas production. Revenue from oil and natural gas operations was $3,346 million for the nine months ended September 30, 2019, an increase of$197 $262 million (46 percent)(8 percent) from $430$3,084 million for 2016. This 2018. The increase was primarily due to the increase in oil and natural gas production, as well asin part due to the increaseRSP 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 include the following:

·average daily

 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
Net production volumes:       
Oil (MBbl)18,940
 16,979
 56,602
 42,947
Natural gas (MMcf)68,411
 56,348
 199,284
 148,633
        
Average prices per unit:       
Realized oil price (Bbl)$54.01
 $56.38
 $53.13
 $59.25
Differential to NYMEX$(2.32) $(13.22) $(3.90) $(7.58)
        
Realized natural gas price (Mcf)$1.34
 $4.18
 $1.70
 $3.63
Average realized natural gas price as a percentage of NYMEX58% 146% 66% 127%
        
total oil production was 119,565 Bbl increased 1,961 MBbl (12 percent) and 13,655 MBbl (32 percent) for the three and nine months ended September 30, 2017, an increase of 28,445 Bbl (31 percent) from 91,120 Bbl for 2016; 

·2019, respectively, as compared to the same periods in 2018; 

average realized oil price (excluding the effects of derivative activities) was $45.29 per Bbl duringdecreased 4 percent and 10 percent for the three months ended September 30, 2017, an increase of 9 percent from $41.52 per Bbl during 2016. For the threeand nine months ended September 30, 2017, our crude oil price differential relative to NYMEX was $(2.83) per Bbl, or a realization of approximately 94 percent,2019, respectively, as compared to a crudethe same periods in 2018. The decrease in average realized oil price differential relativewas primarily due to a decrease in the average NYMEX of $(3.51) per Bbl, or a realization of approximately 92 percent, for 2016.price. The basis differential (referred to as the “Mid-Cush differential”) between the location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location)(settlement location for NYMEX pricing) for our oil directly impacts our realized oil price. For the three months ended September 30, 20172019 and 2016,2018, the average market basis differential between WTI-Midland and WTI-Cushing was aMid-Cush differentials were price reductionreductions of $0.75 $0.61 per Bbl and $0.31 $12.66 per Bbl, respectively. Additionally, we incur fixed deductions fromFor the posted Midland oil price based on the location of our oil within the Permian Basin. These fixed deductions were less per Boe during the threenine months ended September 30, 20172019 and 2018, the average market Mid-Cush differentials were reductions of $2.20 per Bbl and $5.81 per Bbl, respectively;
total natural gas production increased 12,063 MMcf (21 percent) and 50,651 MMcf (34 percent) for the three and nine months ended September 30, 2019, respectively, as compared to 2016 primarily due to more production transported through pipelines;

·average daily natural gas production was 441,587 Mcf for the three months ended September 30, 2017, an increase of 70,978 Mcf (19 percent) from 370,609 Mcf for 2016;same periods in 2018; and

·

average realized natural gas price (excluding the effects of derivative activities) was $3.18 per Mcf duringdecreased 68 percent and 53 percent for the three months ended September 30, 2017, an increase of 31 percent from $2.42 per Mcf during 2016. For the threeand nine months ended September 30, 2017 and 2016, we realized approximately 108 percent and 86 percent,2019, respectively, of the average NYMEX natural gas prices for the respective periods. The increase in our realized natural gas price (excluding the effects of derivatives) as a percentage of NYMEX during the three months ended September 30, 2017 as compared to 2016 was primarily due to an increasethe same periods in the average Mont Belvieu price for a blended barrel of natural gas liquids. Historically, and during the three months ended September 30, 2017, we derived2018. We derive a significant portion of our total natural gas revenues from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. The average Mont Belvieu price for a blended barrel of natural gas liquids was $25.04 decreased from $34.82 per Bbl and $17.82 $30.73 per Bbl during the three and nine months ended September 30, 20172018, respectively, to $16.99 per Bbl and 2016,$20.43 per Bbl during the three and nine months ended September 30, 2019, respectively.

In addition, during the latter part of 2018 and 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 three and nine months ended September 30, 2019, but were partially offset by the value of the natural gas liquids. The combination of these factors resulted in a realized natural gas price of 58 percent and 66 percent of the average NYMEX natural gas price for the three and nine months ended September 30, 2019, respectively, which falls below our historical amounts. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues, our realized natural gas price (excluding the effects of derivatives) historically reflected a price greater than the related NYMEX natural gas price.

38


Oil and natural gas production expenses.  The following table provides the components of our oil and natural gas production expenses for the three and nine months ended September 30, 20172019 and 2016:

2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

  

 

 

Three Months Ended September 30,

 

 

 

 

 

2017

 

 

2016

 

 

 

 

 

 

 

Per

 

 

 

 

Per

(in millions, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

  

$

100

 

$

5.68

 

$

66

 

 $  

4.63

Workover costs

  

 

6

 

 

0.31

 

 

5

 

 

0.35

 

 

Total oil and natural gas production expenses

  

$

106

 

$

5.99

  

$

71

 

 $  

4.98

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Three Months Ended September 30,
 2019 2018
(in millions, except per unit amounts)Amount Per Boe Amount Per Boe
Lease operating expenses$181
 $5.97
 $146
 $5.54
Workover costs9
 0.29
 10
 0.39
Total oil and natural gas production expenses$190
 $6.26
 $156
 $5.93
  Nine Months Ended September 30,
 2019 2018
(in millions, except per unit amounts)Amount Per Boe Amount Per Boe
Lease operating expenses$524
 $5.83
 $388
 $5.73
Workover costs28
 0.31
 28
 0.42
Total oil and natural gas production expenses$552
 $6.14
 $416
 $6.15
        
Lease operating expenses were $100$181 million ($5.685.97 per Boe) for the three months ended September 30, 2017,2019, which was an increase of $34$35 million from $66$146 million ($4.635.54 per Boe) during 2016the same period in 2018. Lease operating expenses were $524 million ($5.83 per Boe) for the nine months ended September 30, 2019, which was an increase of $136 million from $388 million ($5.73 per Boe) during the same period in 2018. The increase in lease operating expenses during both the third quarter of 2017three and nine months ended September 30, 2019 as compared to 2016the same periods in the prior year was primarily the result of an increase in well count due to (i) increased production associated with our acquisitions during 2018, and additional wells successfully drilled and completed in 2016during 2018 and 2017, (ii) our acquisitions2019.
Workover costs were $9 million ($0.29 per Boe) for the three months ended September 30, 2019, which was a decrease of $1 million from $10 million ($0.39 per Boe) during the fourth quarter of 2016 and firstsame period in 2018. Workover costs were $28 million ($0.31 per Boe) for the nine months of 2017ended September 30, 2019 and (iii) an increase$28 million ($0.42 per Boe) during the same period in cost of services.2018. The increasedecrease in lease operating expensesworkover costs per Boe during both the three and nine months ended September 30, 2019 was primarily due to the increase in lease operating expenses noted above including higher expenses per Boe on properties associated with our recent acquisitions in the fourth quarter of 2016 and first nine months of 2017.

increased production.

Production and ad valorem taxes.  The following table provides the components of our production and ad valorem tax expenses for the three and nine months ended September 30, 20172019 and 2016:

2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

  

 

 

Three Months Ended September 30,

 

 

 

 

 

2017

 

 

2016

 

 

 

 

 

 

 

Per

 

 

 

 

Per

(in millions, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes

  

$

44

 

$

2.48

 

$

31

 

 $  

2.25

Ad valorem taxes

  

 

4

 

 

0.22

 

 

2

 

 

0.13

 

 

Total production and ad valorem taxes

  

$

48

 

$

2.70

  

$

33

 

 $  

2.38

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Three Months Ended September 30,
 2019 2018
(in millions, except per unit amounts)Amount Per Boe Amount Per Boe
Production taxes$67
 $2.23
 $79
 $2.98
Ad valorem taxes18
 0.56
 10
 0.39
Total production and ad valorem taxes$85
 $2.79
 $89
 $3.37
  Nine Months Ended September 30,
 2019 2018
(in millions, except per unit amounts)Amount Per Boe Amount Per Boe
Production taxes$207
 $2.31
 $207
 $3.05
Ad valorem taxes48
 0.53
 22
 0.33
Total production and ad valorem taxes$255
 $2.84
 $229
 $3.38
        

Production taxes per unit of production were $2.48$2.23 per Boe during the three months ended September 30, 2017, an increase2019, a decrease of 1025 percent from $2.25$2.98 per Boe during 2016. Over the same period in 2018. Production taxes per unit of production were $2.31 per Boe during the nine months ended September 30, 2019, a decrease of 24 percent from $3.05 per Boe during the same period in 2018. For the three and nine months ended September 30, 2019, our revenue per Boe (excluding the effects of derivatives) increased 15 percent.decreased 19 percent and 18 percent, respectively, as compared to the same periods in 2018. The increasedecrease in production taxes per unit of production was directly relateddue to the increase in oil and natural gas sales, partially offset bylower realized revenue per Boe along with a higher percentage of our total production originating in Texas, which has a lower tax rate than New Mexico. Production taxes fluctuate with the market value of our production sold, while ad valorem taxes are generally based on the valuation of our oil and natural gas properties at the beginning of the year, which vary across the different areas in which we operate.

39



Ad valorem taxes increased $8 million and $26 million for the three and nine months ended September 30, 2019, respectively, as compared to the same periods in 2018, primarily due to additional wells drilled and completed, new wells acquired and an increase in property values and tax rates in certain counties. The increase in ad valorem taxes per Boe was primarily due to an increase in property values and tax rates. 
Gathering, processing and transportation costs.  The following table shows the gathering, processing and transportation costs for the three and nine months ended September 30, 2019 and 2018: 

  Three Months Ended September 30,
 2019 2018
(in millions, except per unit amounts)Amount Per Boe Amount Per Boe
Gathering, processing and transportation costs$25
 $0.82
 $16
 $0.60

  Nine Months Ended September 30,
 2019 2018
(in millions, except per unit amounts)Amount Per Boe Amount Per Boe
Gathering, processing and transportation costs$73
 $0.81
 $36
 $0.53
        

Gathering, processing and transportation costs were $25 million ($0.82 per Boe) for the three months ended September 30, 2019, an increase of 56 percent from $16 million ($0.60 per Boe) during same period in 2018. Gathering, processing and transportation costs were $73 million ($0.81 per Boe) for the nine months ended September 30, 2019, an increase of 103 percent from $36 million ($0.53 per Boe) during same period in 2018. The increase in gathering, processing and transportation costs for both the three and nine months ended September 30, 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 the three and nine months ended September 30, 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, fixed costs associated with certain contracts and higher priced trucking services in certain areas. We entered into a marketing contract that requires us to deliver 50,000 barrels of oil per day starting in October 2019. As a result, we expect our gathering, processing and transportation costs will increase in future periods.
Exploration and abandonments expense. The following table provides the components of our exploration and abandonments expense for the three and nine months ended September 30, 20172019 and 2016:

2018:

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

  

  

 

September 30,

(in millions)

  

2017

 

2016

 

 

 

 

 

 

 

 

Geological and geophysical

  

$

2

 

$

2

Exploratory dry hole costs

  

 

-

 

 

-

Leasehold abandonments

  

 

5

 

 

8

Other

 

 

-

 

 

-

 

Total exploration and abandonments

  

$

7

  

$

10

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2019 2018 2019 2018
Geological and geophysical$3
 $2
 $12
 $9
Leasehold abandonments17
 6
 59
 20
Other6
 2
 19
 7
Total exploration and abandonments$26
 $10
 $90
 $36
        
Our geological and geophysical expense for the periods presented above primarily consists of the costs of acquiring and processing geophysicalsubsurface data to better characterize and core analysis.

Fordevelop our resources.

We recorded $17 million and $6 millionof leasehold abandonments for the three months ended September 30, 20172019 and 2016, we recorded approximately $52018, respectively, and $59 million and $8$20 million respectively, of leasehold abandonments. Forfor the threenine months ended September 30, 2017, our abandonments were2019 and 2018, respectively, primarily related to drillingcertain expiring acreage and acreage where we had no future plans to drill located primarily in the Delaware Basin.

Our other expense for the periods presented above primarily consists of surface and title costs on locations in our Northern Delaware Basin and New Mexico Shelf core areas which, based on multiple factors, arethat we no longer likelyintend to be drilleddrill, certain plugging costs, delay rentals and acreageother exploratory well costs. The increase in our Southern Delaware Basin core area where we have no future development plans. Forother expense for the threenine months ended September 30, 2016, our abandonments were2019, as compared to the same period in 2018 was primarily relateddue to expiring acreage.

the abandonment of one exploratory well during the first quarter of 2019 as a result of certain mechanical issues encountered during the completion of the well that made it unable to produce hydrocarbons.


Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the three and nine months ended September 30, 20172019 and 2016:

2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30,

 

 

 

2017

 

2016

 

 

 

 

 

Per

 

 

 

Per

(in millions, except per unit amounts)

 

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion of proved oil and natural gas properties

 

$

279

 

$

15.67

 

$

294

 

$

20.88

Depreciation of other property and equipment

 

 

5

 

 

0.31

 

 

5

 

 

0.36

Amortization of intangible assets - operating rights

 

 

-

 

 

0.02

 

 

-

 

 

0.03

 

Total depletion, depreciation and amortization

 

$

284

 

$

16.00

 

$

299

 

$

21.27

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil price used to estimate proved oil reserves at period end

 

$

46.27

 

 

 

 

$

38.17

 

 

 

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

 

$

3.00

 

 

 

 

$

2.28

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 Three Months Ended September 30,
 2019 2018
(in millions, except per unit amounts)Amount Per Boe Amount Per Boe
Depletion of proved oil and natural gas properties$478
 $15.80
 $401
 $15.19
Depreciation of other property and equipment9
 0.26
 5
 0.20
Amortization of intangible assets1
 0.01
 —
 0.04
Total depletion, depreciation and amortization$488
 $16.07
 $406
 $15.43
 Nine Months Ended September 30,
 2019 2018
(in millions, except per unit amounts)Amount Per Boe Amount Per Boe
Depletion of proved oil and natural gas properties$1,405
 $15.66
 $1,015
 $14.99
Depreciation of other property and equipment23
 0.25
 16
 0.24
Amortization of intangible assets3
 0.02
 2
 0.04
Total depletion, depreciation and amortization$1,431
 $15.93
 $1,033
 $15.27
 September 30, 2019 September 30, 2018
Oil price used to estimate proved oil reserves at period end$54.27
 $59.92
Natural gas price used to estimate proved natural gas reserves at period end$2.87
 $2.91
    
Depletion of proved oil and natural gas properties was $279$478 million ($15.6715.80 per Boe) for the three months ended September 30, 2017 and $2942019, an increase of $77 million (19 percent) from $401 million ($20.8815.19 per Boe) for 2016.2018. Depletion of proved oil and natural gas properties was $1,405 million ($15.66 per Boe) for the nine months ended September 30, 2019, an increase of $390 million (38 percent) from $1,015 million ($14.99 per Boe) for 2018. The decreaseincrease in depletion expense was primarily due to a loweran increase in production and the depletion rate per Boe period over period partially offset by anBoe. The increase in production. The decrease in depletion expense per Boe period over period was primarily due to (i) lower drillingthe RSP Acquisition and completion costs per Boe of proved developed reserves added and (ii) an overall increase in proved reserves period over period primarily duecertain downward adjustments to our successful exploratory drilling program, the Reliance Acquisition, the Northern Delaware Basin acquisition, the Midland Basin acquisition, reductions in future estimated lease operating expenses and an increase in commodity prices period over period, partially offset by decreased proved reserves caused by reclassification of proved undeveloped reserves to unproved reserves because they are no longer expected to be developed within five years of their initial recording.

Impairments of long-lived assets. We periodically review our long-lived assets to be held and used, including proved oil and natural gas reserves, partially offset by lower depletion of the Yeso field due the impairment charge recognized during the second quarter of 2019, as discussed below, and the cessation of the depletion expense for the New Mexico Shelf assets classified as held for sale at August 29, 2019.

Impairments of long-lived assets. During the three and nine months ended September 30, 2019, we recognized impairment charges of $101 million and $969 million, respectively. 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 thatin 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 thosethe remaining assets may not be recoverable, for instance when there are declines in commodity prices or well performance. We

40

review our oil and natural gas properties by depletion base. An impairment lossthe Yeso field to their fair value. Our Yeso field is indicated if the sumprimarily composed of the expected undiscounted future net cash flows is less thanNew Mexico Shelf assets that we expect to sell in November 2019. The impairments during the carrying amountthird quarter of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of our assets, we recognize2019 also included an impairment losscharge related to the New Mexico Shelf assets that we classified as held for sale at August 29, 2019, including an impairment charge of $81 million related to the amount by which the carrying amountimpairment of the asset exceeds the estimated fair value of the asset.

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

We estimate fair values of our long-lived assets and their integrated assets using a discounted future cash flow model. Fair value assumptions associated with the calculation of discounted future net cash flows include (i) market estimates of commodity prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, (vii) prevailing market rates of income and expenses from integrated assets and (viii) discount rate. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value.disposal group. We did not recognize an impairment charge during 2018. See Note 6 of the three months ended September 30, 2017 or 2016.

Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on the fair value assumptions used for long-lived assets and assets held for sale.

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 ofchanges in income and expenses from integrated assets.

Based on economic factors at September 30, 2017, we determined that undiscounted future cash flows attributable to our North Basin Bone Spring (“NBBS”) field located in the Northern Delaware Basin with a net book value of approximately $1.1 billion indicated that its carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows). We estimate that if the future oil and natural gas prices used in this analysis, and noted above, would have been approximately 10 percent lower at September 30, 2017 with no other changes in capital costs, operating costs, price differentials, or reserve performance curves, we could have recognized a non-cash impairment in that period of approximately $470 million related to our NBBS field. Other assumptions such as operating costs, well and reservoir performance, severance and ad valorem taxes, and operating and development plans would likely change given a change in oil and natural gas prices. However, we did not estimate the correlation between these assumptions and any estimated commodity price change, and these and other assumptions may worsen or partially mitigate some of the effects of a reduction in commodity prices, including the ultimate impact and amount of any potential impairment charge. As a result, we are unable to predict with certainty whether or not a decline in commodity prices alone will cause us to recognize an impairment charge in a particular field or the magnitude of any such impairment charge. We additionally note that there may be changes to both drilling and completion designs that affect the volume curves, capital costs estimates, and the amount of proved undeveloped locations that can be recorded, each of which will affect management’s estimates of future cash flows.

41




General and administrative expenses.The following table provides components of our general and administrative expenses for the three and nine months ended September 30, 20172019 and 2016:

2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30,

 

 

 

2017

 

2016

 

 

 

 

 

 

Per

 

 

 

 

Per

(in millions, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

  

$

51

 

$

2.89

 

$

42

 

$

3.04

Less: Operating fee reimbursements

  

 

(4)

 

 

(0.24)

 

 

(4)

 

 

(0.29)

Non-cash stock-based compensation

  

 

17

 

 

0.95

 

 

15

 

 

1.05

 

Total general and administrative expenses

  

$

64

 

$

3.60

  

$

53

 

$

3.80

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General

 Three Months Ended September 30,
 2019 2018
(in millions, except per unit amounts)Amount Per Boe Amount Per Boe
General and administrative expenses$60
 $2.01
 $65
 $2.46
Less: Operating fee reimbursements(5) (0.15) (4) (0.19)
Non-cash stock-based compensation20
 0.64
 23
 0.86
Total general and administrative expenses$75
 $2.50
 $84
 $3.13
 Nine Months Ended September 30,
 2019 2018
(in millions, except per unit amounts)Amount Per Boe Amount Per Boe
General and administrative expenses$200
 $2.22
 $176
 $2.60
Less: Operating fee reimbursements(13) (0.14) (13) (0.20)
Non-cash stock-based compensation67
 0.74
 58
 0.86
Total general and administrative expenses$254
 $2.82
 $221
 $3.26
        
Total general and administrative expenses were approximately $64$75 million ($3.602.50 per Boe) for the three months ended September 30, 2017, an increase2019, a decrease of $11$9 million (21(11 percent) from $53$84 million ($3.803.13 per Boe) for 2016.during the same period in 2018. The increasedecrease in cash general and administrative expenses was primarily driven by increased compensation expense as a result of increased employee headcount. The increase in non-cash stock-based compensation was primarily due to lower variable compensation accruals during the increase in employee headcount coupled with lower forfeitures in the third quarter of 2017. current period. The decrease in total general and administrative expenses per Boe was primarily the result of the decrease in general and administrative expenses and increased production.
Total general and administrative expenses were $254 million ($2.82 per Boe) for the nine months ended September 30, 2019, an increase of $33 million (15 percent) from $221 million ($3.26 per Boe) during the same period in 2018. The increases in cash general and administrative and non-cash stock-based compensation expenses were primarily the result of increased employee headcount, in part due to the RSP Acquisition, partially offset by lower variable compensation accruals during the third quarter of 2019 noted above. The decrease in total general and administrative expenses per Boe was primarily the result of increased production, period over period, partially offset by the increase in 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 to general and administrative expenses inon the consolidated statements of operations. We earned reimbursements of approximately $4$5 million for each ofand $4 million during the three months ended September 30, 20172019 and 2016. 

2018, respectively, and $13 million during both the nine months ended September 30, 2019 and 2018.

42


Gain (loss) on derivatives.The following table sets forth the gain (loss) on derivatives for the three and nine months ended September 30, 20172019 and 2016:

2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

September 30,

(in millions)

 

 

2017

 

 

2016

 

 

 

 

 

 

 

 

 

Gain (loss) on derivatives:

 

 

 

 

 

 

 

Oil derivatives

 

$

(205)

 

$

36

 

Natural gas derivatives

 

 

(1)

 

 

5

 

 

Total

 

$

(206)

 

$

41

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

September 30,

(in millions)

 

 

2017

 

 

2016

 

 

 

 

 

 

 

 

 

Net cash receipts from derivatives:

 

 

 

 

Oil derivatives

 

$

28

 

$

154

 

Natural gas derivatives

 

  

2

 

    

1

 

 

Total

 

$

30

 

$

155

 

 

 

 

 

 

 

 

 

 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2019 2018 2019 2018
Gain (loss) on derivatives:       
Oil derivatives$355
 $(626) $(506) $(787)
Natural gas derivatives42
 1
 61
 (6)
Total$397
 $(625) $(445) $(793)
        
The following table represents our net cash receipts from (payments on) derivatives for the three and nine months ended September 30, 2019 and 2018:
 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2019 2018 2019 2018
Net cash receipts from (payments on) derivatives:   
    
Oil derivatives$(21) $(46) $(72) $(245)
Natural gas derivatives14
 2
 15
 7
Total$(7) $(44) $(57) $(238)
        
Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains,gains; while to the extent the future commodity price outlook increases between measurement periods, we will have mark-to-market losses. See Note 6 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding significant judgments made in classifying financial instruments in the fair value hierarchy.

Interest expense. Interest expense was $39 million for

Gain (loss) on disposition of assets, net. During each of the three monthsand nine month periods ended September 30, 2017 as compared to $532019, we recorded a gain of $303 million, during 2016. The decrease was primarily due to (i) approximately $11 million of interest expense related to our $600 million 7.0% unsecured senior notes due 2021 (the “7.0% Notes”) that were redeemedcontribution of certain infrastructure assets in September 2016exchange for a cash distribution and (ii) approximately $10 million ofan equity ownership interest expense related to our $600 million 6.5% unsecured senior notes due 2022 (the “6.5% Notes”) that were satisfied and discharged in December 2016, partially offset by approximately $7 million of interest expense related to our $600 million 4.375% unsecured senior notes due 2025 (the “4.375% Notes”) issued in December 2016.

Loss on extinguishment of debt.We recorded a loss on extinguishment of debt of approximately $65 million for the three months ended September 30, 2017. This amount includes 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.

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

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

43

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

Oil and natural gas revenues.  Revenue from oil and natural gas operations was$1,806 million for the nine months ended September 30, 2017, an increase of$696 million (63 percent) from $1,110 million for 2016. This increase was primarily due to the increase in oil and natural gas production as well as the increase in realized oil and natural gas prices (excluding the effects of derivative activities). Specific factors affecting oil and natural gas revenues include the following:

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

·average realized oil price (excluding the effects of derivative activities) was $46.34 per Bbl during the nine months ended September 30, 2017, an increase of 23 percent from $37.75 per Bbl during 2016. Forentity. During the nine months ended September 30, 2017, our crude oil price differential relative to NYMEX was $(3.11) per Bbl, or2018, we recorded a realizationgain on disposition of approximately 94 percent, as compared to a crude oil price differential relative to NYMEXassets of $(3.70) per Bbl, or a realization of approximately 91 percent, for 2016. The basis differential between the location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil directly impacts our realized oil price. For the nine months ended September 30, 2017 and 2016, the average market basis differential between WTI-Midland and WTI-Cushing was a price reduction of $0.31 per Bbl and $0.11 per Bbl, respectively. Additionally, we incur fixed deductions from the posted Midland oil price based on the location of our oil within the Permian Basin. These fixed deductions were less per Boe during the nine months ended September 30, 2017 as compared to 2016 primarily due to more production transported through pipelines and successful renegotiation of fixed deductions for trucked volumes;

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

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

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

44

Oil and natural gas production expenses.  The following table provides the components of our oil and natural gas production expenses for the nine months ended September 30, 2017 and 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

  

 

Nine Months Ended September 30,

 

 

 

 

2017

 

2016

 

 

 

 

 

 

 

Per

 

 

 

 

Per

(in millions, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

  

$

278

 

$

5.47

 

$

225

 

$

5.62

Workover costs

  

 

15

 

 

0.29

 

 

15

 

 

0.38

 

 

Total oil and natural gas production expenses

  

$

293

 

$

5.76

  

$

240

 

$

6.00

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses were $278$719 million ($5.47 per Boe) for the nine months ended September 30, 2017, which was an increase of $53 million from $225 million ($5.62 per Boe) during 2016. The increase in lease operating expenses during the nine months ended September 30, 2017 as compared to 2016 was primarily due to (i) increased production associated with our wells successfully drilled and completed in 2016 and 2017, (ii) our acquisitions during the fourth quartera gain of 2016 and first nine months of 2017 and (iii) increased cost of services, partially offset by a decrease in facility expense. The decrease in lease operating expenses per Boe was primarily due to increased production during the first nine months of 2017 as compared to 2016, partially offset by the increase in total lease operating expenses as noted above.

Production and ad valorem taxes.  The following table provides the components of our production and ad valorem tax expenses for the nine months ended September 30, 2017 and 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

  

 

Nine Months Ended September 30,

 

 

 

 

2017

 

2016

 

 

 

 

 

 

 

Per

 

 

 

 

Per

(in millions, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes

  

$

128

 

$

2.52

 

$

78

 

 $  

1.96

Ad valorem taxes

  

 

12

 

 

0.23

 

 

11

 

 

0.27

 

 

Total production and ad valorem taxes

  

$

140

 

$

2.75

  

$

89

 

 $  

2.23

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes per unit of production were $2.52 per Boe during the nine months ended September 30, 2017, an increase of 29 percent from $1.96 per Boe during 2016. Over the same period, our revenue per Boe (excluding the effects of derivatives) increased 28 percent. The increase in production taxes per unit of production was directly related to the increase in oil and natural gas sales. Additionally, tax credits of approximately $4 million were received during the first quarter of 2016 related to certain wells in Texas qualifying for reduced severance tax rates. Production taxes fluctuate with the market value of our production sold, while ad valorem taxes are generally based on the valuation of our oil and natural gas properties at the beginning of the year, which vary across the different areas in which we operate.

45

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

 

 

 

 

 

 

 

 

  

  

 

Nine Months Ended

 

 

 

September 30,

(in millions)

  

2017

 

2016

 

 

 

 

 

 

 

 

Geological and geophysical

  

$

9

 

$

6

Exploratory dry hole costs

  

 

-

 

 

7

Leasehold abandonments

 

 

29

 

 

40

Other

  

 

4

 

 

1

 

Total exploration and abandonments

  

$

42

  

$

54

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

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

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

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

Nine Months Ended September 30,

 

 

 

2017

 

2016

 

 

 

 

 

 

 

Per

 

 

 

 

 

Per

(in millions, except per unit amounts)

  

 

Amount

 

 

Boe

 

 

Amount

 

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion of proved oil and natural gas properties

  

$

830

  

$

16.31

  

$

874

  

$

21.86

Depreciation of other property and equipment

  

 

17

 

 

0.33

 

 

15

 

 

0.38

Amortization of intangible assets - operating rights

  

 

1

 

 

0.02

 

 

1

 

 

0.03

 

Total depletion, depreciation and amortization

  

$

848

  

$

16.66

  

$

890

  

$

22.27

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

46

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

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

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

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

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

Based on economic factors at September 30, 2017, we determined that undiscounted future cash flows attributable to our NBBS field located in the Northern Delaware Basin with a net book value of approximately $1.1 billion indicated that its carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows). We estimate that if the future oil and natural gas prices used in this analysis, and noted above, would have been approximately 10 percent lower at September 30, 2017 with no other changes in capital costs, operating costs, price differentials, or reserve performance curves, we could have recognized a non-cash impairment in that period of approximately $470$575 million related to our NBBS field. Other assumptions such as operating costs, wellFebruary 2018 acquisition and reservoir performance, severancedivestiture, (ii) a gain of $134 million related to our January 2018 Delaware Basin divestitures and ad valorem taxes, and operating and development plans would likely change given(iii) a change in oil and natural gas prices. However, we did not estimate the correlation between these assumptions and any estimated commodity price change, and these and other assumptions may worsen or partially mitigate somegain 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

47

unable$15 million related to predict with certainty whether or not a decline in commodity prices alone will cause us to recognize an impairment charge in a particular field or the magnitude of any such impairment charge. We additionally note that there may be changes to both drilling and completion designs that affect the volume curves, capital costs estimates, and the amount of proved undeveloped locations that can be recorded, each of which will affect management’s estimates of future cash flows.

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

 

Nine Months Ended September 30,

 

 

 

2017

 

2016

 

 

 

 

 

 

Per

 

 

 

 

Per

(in millions, except per unit amounts)

  

Amount

 

Boe

 

Amount

 

Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

  

$

149

 

$

2.95

 

$

129

 

$

3.24

Less: Operating fee reimbursements

  

 

(12)

 

 

(0.24)

 

 

(12)

 

 

(0.30)

Non-cash stock-based compensation

  

 

43

 

 

0.85

 

 

43

 

 

1.08

 

Total general and administrative expenses

  

$

180

 

$

3.56

 

$

160

 

$

4.02

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

We receive fees for the operation of jointly-owned 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 approximately $12 million for each of the nine months ended September 30, 2017 and 2016.

48

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

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

 

 

 

September 30,

(in millions)

 

 

2017

 

 

2016

 

 

 

 

 

 

 

 

 

Gain (loss) on derivatives:

 

 

 

 

 

 

 

Oil derivatives

 

$

260

 

$

(173)

 

Natural gas derivatives

 

 

29

 

 

(3)

 

 

Total

 

$

289

 

$

(176)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

 

 

 

September 30,

(in millions)

 

 

2017

 

 

2016

 

 

 

 

 

 

 

 

 

Net cash receipts from (payments on) derivatives:

 

 

 

 

Oil derivatives

 

$

129

 

$

566

 

Natural gas derivatives

 

  

(3)

 

    

16

 

 

Total

 

$

126

 

$

582

 

 

 

 

 

 

 

 

 

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent the future commodity price outlook increases between measurement periods, we will have mark-to-market losses.certain nonmonetary transactions. See Note 64 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding significant judgments madeinformation.

Interest expense.  The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the three and nine months ended September 30, 2019 and 2018:
 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2019 2018 2019 2018
Interest expense, as reported$46
 $46
 $141
 $103
Capitalized interest6
 2
 15
 5
Interest expense, excluding impact of capitalized interest$52
 $48
 $156
 $108
        
Weighted average interest rate - credit facility4.0% 4.8% 4.3% 4.6%
Weighted average interest rate - senior notes4.4% 4.4% 4.4% 4.3%
Total weighted average interest rate4.3% 4.4% 4.4% 4.3%
        
Weighted average credit facility balance$458
 $152
 $530
 $138
Weighted average senior notes balance4,000
 3,982
 4,000
 2,927
Total weighted average debt balance$4,458
 $4,134
 $4,530
 $3,065
        
The increase in classifying financial instrumentsinterest expense during the nine months ended September 30, 2019 as compared to the same period in the fair value hierarchy.

Gainprior year was primarily due to the increase in the weighted average debt balance, partially offset by the increase in capitalized


interest and lower weighted average interest rate on dispositionthe Credit Facility. The increase in the weighted average debt balance was primarily due to the senior notes issued in connection with the RSP Acquisition and a higher average outstanding balance under the Credit Facility. 
Other, net. During the nine months ended September 30, 2019, we recorded other income of assets, net. In February 2017, we closed on our previously announced divestiture$311 million, primarily related to $289 million of our ownership interest in ACC. After adjustments for debt and working capital, we received cash proceeds from the sale of approximately $801 million. After direct transaction costs, we recordedour ownership interest in Oryx I, a pre-tax gain on disposition of assets of approximately $655 million. Our net investment in ACC at the time of closing was approximately $129 million.

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

Interest expense. Interest expense was $118 million for("Oryx I"). During the nine months ended September 30, 2017 as compared2018, we recorded other income of $108 million primarily related to $162a cash distribution received from Oryx. See Note 2 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information.

Income tax provisions.  We recorded an income tax expense of $222 million during 2016.and an income tax benefit of $69 million for the three months ended September 30, 2019 and 2018, respectively. The decreasechange in the income tax provision was primarily due to (i) approximately $32 million of interest expense relatedthe pre-tax income for the three months ended September 30, 2019 as compared to our $600 million 7.0% Notes that were redeemed inthe pre-tax loss for the three months ended September 2016 and (ii) approximately $29 million of interest expense related to our $600 million 6.5% Notes that were satisfied and discharged in December 2016, partially offset by approximately $20 million of interest expense related to our $600 million 4.375% Notes issued in December 2016.

Loss on extinguishment of debt.30, 2018. We recorded a loss on extinguishmentan income tax benefit of debt$25 million and an income tax expense of approximately $66$225 million for the nine months ended September 30, 2017. This amount includes (i) approximately $36 million associated with2019 and 2018, respectively. The change in the premium paidincome tax provision was primarily due to the pre-tax loss for the Tender Offer, approximately $25 million associated withnine months ended September 30, 2019 as compared to the make-whole premium paidpre-tax income for the early extinguishmentnine months ended September 30, 2018.

Our effective income tax rates were 29 percent and 26 percent for the three months ended September 30, 2019 and 2018, respectively, and 10 percent and 23 percent for the nine months ended September 30, 2019 and 2018, respectively. At the end of each interim period, we apply a forecasted annualized effective tax rate to the current period income or loss before income taxes, which can produce interim effective tax rate fluctuations. The difference between the Company’s effective tax rates for the three and nine months ended September 30, 2019 as compared to the same periods in 2018 was primarily due to research and development credit, net of unrecognized tax benefits, recorded in 2019, and the impact of permanent differences between book and taxable income (loss). The lower effective tax rate during 2019 was partially the result of the 5.5% Notes, approximately $21 million of unamortized deferred loan costs and approximately $2 million of additional interest onpermanent differences primarily related to the 5.5% Notes to October 13, 2017, which was paid in September 2017, reduced by approximately $19 million of unamortized premium; and (ii) approximately $1 million representing the proportional amount of unamortized deferred loan costs associated with banks that are no longer in the credit facility syndicatediscrete, non-deductible goodwill impairment recognized as a result of the April 2017 credit facility amendment.

pending New Mexico Shelf divestiture.

49

WeDuring the second quarter of 2019, the state of New Mexico enacted a tax law which, among other changes, amended the net operating loss apportioned carryforwards for corporations. As a result of this law change, we recorded a loss on extinguishmentan estimated deferred state tax benefit of debt of approximately $28$6 million for the nine months ended September 30, 2016. This amount includes $21 million associated with the make-whole premium paid for the early redemption of the 7.0% Notes and approximately $7 million of unamortized deferred loan costs.

Income tax provisions.  We recorded income tax expense of $398 million, which includes a discrete income tax benefit of approximately $6 million related to excess tax benefits on stock-based awards, which are recorded in the income tax provision pursuant to ASU No. 2016-09, which was adopted on January 1, 2017, and an income tax benefit of $782 million for the nine months ended September 30, 2017 and 2016, respectively. The change in our income tax provision was primarily due to income before income taxes during the nine months ended September 30, 2017, as compared to a loss before income taxes during 2016. The effective income tax rates for the nine months ended September 30, 2017 and 2016 were 36.6 percent and 36.9 percent, respectively.

2019.

50



Capital Commitments, Capital Resources and Liquidity

Capital commitments. Our primary needs for cash are for (i) the development, exploration and acquisition of oil and natural gas assets, (ii) midstream joint ventureventures 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

2019 capital budget and natural gas properties. costs incurred. We expect our 2019 capital spending on drilling and completion activity to range between $2.8 billion and $3.0 billion. Our costs incurred on oil and natural gas properties, excluding acquisitions, during the nine months ended September 30, 2017 and 20162019 totaled $1.2 billion and $800 million, respectively. The increase was primarily due to our increased drilling and completion activity level during the first nine months of 2017 as compared to 2016. Our intent is to manage our capital spending to be within our cash flow, excluding unbudgeted acquisitions.$2.4 billion. The primary reason for the differences in costs incurred and cash flow expenditures was our issuance of approximately 2.2 million shares of common stock related to our Northern Delaware Basin acquisition andthe timing of payments. Total 2017Our capital expenditures for the nine months ended September 30, 2019 were primarily funded in part from (i) cash flows from operations (ii)and borrowings under our issuanceCredit Facility.
Other than the customary purchase of approximately 2.2 million sharesleasehold acreage, our capital budgets are exclusive of common stock relatedacquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek to acquire oil and natural gas properties that provide opportunities for the addition of reserves and production through a combination of development, high-potential exploration and control of operations that will allow us to apply our Northern Delaware Basin acquisition and tooperating expertise.
2019 dividends. On October 29, 2019, our board of directors approved a lesser extent (iii) proceeds from our February 2017 divestiturecash dividend of ACC.

2017 capital budget. In February 2017, we announced our updated 2017 capital budget, excluding acquisitions,$0.125 per share for the fourth quarter of approximately $1.8 billion with expected capital spending to range between $1.6 billion and $1.8 billion. Approximately 90 percent of capital will be directed to drilling and completion activity. Our 2017 capital program, based on our current expectations of commodity prices and costs,2019 that is expected to be withinpaid on December 20, 2019 to stockholders of record as of November 8, 2019. Total cash dividends, including the cash dividends on unvested restricted stock awards, paid to our cash flows. However, ifstockholders during the nine months ended September 30, 2019 were $75 million. We intend to continue to pay a quarterly dividend of $0.125 in the near future; however, any payment of future dividends will be at the discretion of our board of directors and may be suspended at any time.

Share repurchase program. In September 2019, we wereannounced that our board of directors authorized the initiation of a share repurchase program for up to outspend$1.5 billion of our cash flows,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 believe we couldare not obligated to acquire any specific number of shares.
We intend to use our credit facilitya portion of the proceeds from the New Mexico Shelf divestiture, which is expected to close in November 2019, to initiate share repurchases in the fourth quarter of 2019, and other financing sourcesmaintain sufficient liquidity to fund any cash flow deficits. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the costs of drilling rigs and other services and equipment, regulatory, technological and competitive developments, commodity prices, leverage metrics and industry conditions. In addition, under certain circumstances, we may consider increasing, decreasing or reallocating our capital spending plans.

commitments and dividend payments. All additional future repurchases will require the approval of the Company's board of directors. As of September 30, 2019, we have not repurchased any common stock under this program.

Acquisitions.The following table reflects ourour expenditures for acquisitions of proved and unproved properties for the nine months ended September 30, 20172019 and 2016:

2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

 

 

 

September 30,

(in millions)

 

2017

 

2016

 

 

 

 

 

 

 

 

 

Property acquisition costs:

  

 

 

 

 

 

 

Proved

 

$

301

 

$

257

 

Unproved

 

 

865

 

 

172

 

 

Total property acquisition costs (a)

  

$

1,166

 

$

429

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Included in the property acquisition costs above are budgeted unproved leasehold acreage acquisitions of approximately $26 million for each of the nine months ended September 30, 2017 and 2016. For the nine months ended September 30, 2017, our unbudgeted acquisitions are primarily comprised of approximately $603 million and $452 million of property acquisition costs related to our Midland Basin and Northern Delaware Basin acquisitions, respectively. For the nine months ended September 30, 2016, our unbudgeted acquisitions are primarily comprised of approximately $375 million of property acquisition costs related to our Southern Delaware Basin acquisition.

 

 

 

 

 

 

 

 

 

 

 

 

 Nine Months Ended September 30,
(in millions)2019 2018
Property acquisition costs:   
Proved$—
 $4,126
Unproved33
 3,596
Total property acquisition costs (a)$33
 $7,722
    
(a) Total property acquisition costs for the nine months ended September 30, 2019 were primarily composed of budgeted unproved leasehold acreage acquisitions. For the nine months ended September 30, 2018, our property acquisition costs were primarily related to $7.6 billion of unbudgeted property acquisition costs related to the RSP Acquisition.
Contractual obligations.Our contractual obligations include long-term debt, cash interest expense on debt, derivative liabilities, asset retirement obligations, employment agreements with officers, purchase obligations, operating and finance lease obligations and other obligations. Since December 31, 2016,2018, there have been the following material changes in our contractual obligations are not material, other than our cash interest expense onobligations:
$153 million increase in long-term debt and our derivative liability position. Cash interest expense on debt increased by $854 million due to the issuanceadditional borrowings under our Credit Facility; and
a marketing contract that requires us to deliver 50,000 barrels of the Notes which have maturity dates of 2027 and 2047, as compared to the retired 5.5% Notes

oil per day.

51

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

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 2017, we announcedOctober 2018, our updated 2017board of directors approved our 2019 capital budget excluding acquisitions, of approximately $1.8 billion with expected capital spendingup to range$3.8 billion. With current commodity prices, we expect to spend between $1.6 $2.8

billion and $1.8 billion. Our 2017$3.0 billion on drilling and completion activity. We expect to fund the remainder of our 2019 capital program, based on our current expectations of commodity prices and costs, is expected to be within our cash flows. However, if we were to outspend ourbudget with operating cash flows we believe we could useand borrowings under our credit facility and other financing sources to fund any cash flow deficits. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the costs of drilling rigs and other services and equipment, regulatory, technological and competitive developments, commodity prices, leverage metrics and industry conditions. In addition, under certain circumstances, we may consider increasing, decreasing or reallocating our capital spending plans.

Credit Facility.

The following table summarizes our changes in cash and cash equivalents for the nine months endedSeptember 30, 20172019 and 2016:

2018:

 

 

 

 

 

 

 

 

 

  

 

  

 

Nine Months Ended

 

 

 

 

September 30,

(in millions)

 

2017

 

2016

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

  

$

1,185

 

$

1,019

Net cash used in investing activities

  

 

(1,207)

 

 

(783)

Net cash provided by (used in) financing activities

  

 

(31)

 

 

694

 

Net increase (decrease) in cash and cash equivalents

  

$

(53)

 

$

930

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 Nine Months Ended September 30,
(in millions)2019 2018
Net cash provided by operating activities$2,067
 $1,861
Net cash used in investing activities(2,020) (1,422)
Net cash used in financing activities(47) (415)
Net increase in cash and cash equivalents$—
 $24
    
Cash flow from operating activities.The increase in operating cash flows during the nine months endedSeptember 30, 20172019 as compared to the same period in 20162018 was primarily due to an increase in oil and natural gas revenues of approximately $696$262 million and a decrease in cash interest expensean increase of approximately $42$181 million partially offset by (i) approximately $126 due to $57 million fromof settlements paid on derivatives during the nine months ended September 30, 2017,2019, as compared to $582 million from settlements on derivatives during the comparable period in 2016, (ii) approximately $53 million increase in production expense, (iii) approximately $51 million increase in production tax expense and (iv) a decrease in operating cash flow of approximately $20 million due to cash tax expense of approximately $6 million for the nine months ended September 30, 2017, as compared to a cash tax benefit of approximately $14$238 million during the comparable period in 2016.

2018. The increase was partially offset by increased operating costs on our oil and natural gas properties.

Our net cash provided by operating activities included a reduction of approximately $59$8 million and $73a benefit of $3 million for the nine months ended September 30, 20172019 and 2016,2018, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

Cash flow from investing activities.During the nine months ended September 30, 2017 Our investing activities consist primarily of drilling and 2016, we invested approximately $1,958 millioncompletion activity, acquisitions and $927 million, respectively, for capital expendituresdivestitures. The primary difference between costs incurred on oil and natural gas properties, including acquisitions, and cash flow expenditures is the timing of payments and the issuances of shares of common stock to fund certain acquisitions.
For the nine months endedSeptember 30, 2019, our net cash used in investing activities was $2.0 billion, which consisted primarily of our investment of $2.4 billion for additions to oil and natural gas properties. Additionally,This was partially offset by $393 million of cash proceeds from asset dispositions primarily due to the sale of Oryx I and the contribution of certain water infrastructure assets. In addition, we received approximately $803 a $93 million related todeposit for the pending divestiture of the New Mexico Shelf assets. We used the proceeds from these and other divestitures to repay a portion of our outstanding balance under our Credit Facility. Our capital expenditures for the disposition of assets during the nine months endedSeptember 30, 2017, as compared2019 were funded with cash flows from operations and borrowings under our Credit Facility.
For the nine months ended September 30, 2018, our net cash used in investing activities was $1.4 billion, which consisted primarily of our investment of $1.7 billion for additions to $296 oil and natural gas properties, partially offset by $260 million of proceeds received from asset dispositions and a distribution received from our equity method investment. We received a distribution from Oryx of $157 million during the comparable periodnine months ended September 30, 2018. Of this amount, $9 million represented cumulative Oryx earnings and was classified as cash flow from operating activities, while the remaining amount of 2016.

$148 million was classified as cash flow from investing activities.

52

Cash flow from financing activities.Net For the nine months ended September 30, 2019, our net cash used by financing activities was $47 million primarily due to $153 million of net borrowings under our Credit Facility partially offset by $75 million of dividends paid on our common stock. During the nine months ended September 30, 2019 we decreased our book overdraft by $104 million.

For the nine months ended September 30, 2018, our net cash used in financing activities was approximately $31$415 million. We had $129 million for the nine months ended September 30, 2017 whileof net cash provided by financing activities was approximately $694 million for the nine months ended September 30, 2016. Below is a description ofpayments on our significant financing activities:

·Credit Facility during this period. In September 2017,July 2018, we issued $1,800 million$1.6 billion in aggregate principal amount of the Notes, for which we received net proceeds of approximately $1,777 million. Wesenior unsecured notes, and used the net proceeds fromto redeem and cancel certain senior unsecured notes assumed in the offering, togetherRSP 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 approximately $68 million. We also paid accrued interest of approximately $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 $1,232including $1 million principal amount of our 5.5% Notes at a price equal to 102.934 percent of par and (ii) satisfaction and discharge of our remaining obligations of $918 million principal amount under the indentures of the 5.5% Notes at a price equal to 102.75 percent of par. The early extinguishment price included approximately $36 million associated with the premium paid for the Tender Offer, approximately $25 million for the make-whole premium paid for the early extinguishment of the 5.5% Notes and approximately $2 million for prepaid interest as part of the satisfaction and discharge.

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

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

·During the first nine months of 2017, we borrowed $368 million on our credit facility.

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

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

accrued interest.

Advances on our 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 (4.25 percent at September 30, 2017), (b) the federal funds effective rate plus 0.5 percent and (c) the London Interbank Offered Rate (“LIBOR”) plus 1.0 percent or (ii) LIBOR. The credit facility’son:
(i)an alternative base rate (“ABR”), which is equal to the highest of
(a)the prime rate of JPMorgan Chase Bank (5.0 percent at September 30, 2019),
(b)the federal funds effective rate plus 0.5 percent, and
(c)the London Interbank Offered Rate (“LIBOR”) plus 1.0 percent; or

(ii)LIBOR plus 1.5 percent.
Our Credit Facility’s interest rates and commitment fees on the unused portion of the available commitment vary depending on our credit ratings from Moody’s Investors Service, Inc. (“Moody’s”) and S&P Global Ratings (“S&P”). At our current credit ratings, LIBOR Rate Loans and Alternate Base Rate Loans bear interest margins of 150 basis points and 50 basis points per annum, respectively, and commitment fees on the unused portion of the available commitment are 25 basis points per annum.In September 2017, we elected to enter into an Investment Grade Period under our credit facility, which had the effect of releasing all collateral formerly securing the credit facility. If the Investment Grade Period under the credit facility terminates (whether automatically or by our election), the credit facility will once again be secured by a first lien on substantially all of our oil and natural gas properties and by a pledge of the equity interests in our subsidiaries.

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

Credit Facility.

Liquidity. Our principal source of liquidity is the available borrowing capacity under our credit facility. Credit Facility. At September 30, 2017,2019, our commitments from our bank group were $2.0 billion.

billion, of which $1.6 billion were unused commitments.

Debt ratings.We receive debt credit ratings from S&P, Moody’s and Fitch Ratings (“Fitch”), whichand are subject to regular reviews. In August 2017, our long-term debt was assigned a first-timedesignated 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,

53

debt levels and asset and reserve mix. An explanation of the significance of each rating may be obtained from the applicable rating agency.

A downgrade in our credit ratings could (i) negatively impact our costscost 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 Periodinvestment grade period under our Credit Facility will automatically terminate and cause the credit facilityour 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 materialan adverse effect on our business, financial condition and results of operations.

As of the filing of this Quarterly Report on Form 10-Q, no changes in our credit ratings have occurred since September 30, 2017;occurred; however, we cannot be assuredcertain that our credit ratings will not be downgraded in the future.

Book capitalization and current ratio. ratio. Our net book capitalization at September 30, 20172019 was $11.3$22.8 billion, consisting of debt of $2.7 billion$4.3 billion and stockholders’ equity of $8.6 $18.5 billion. Our net book capitalization at December 31, 20162018 was $10.2$23.0 billion, consisting of $0.1 billion of cash and cash equivalents, debt of $2.7$4.2 billion and stockholders’ equity of $7.6$18.8 billion. Our ratio of net debt to net book capitalization was 2419 percent and 26 18 percent at September 30, 20172019 and December 31, 2016,2018, respectively. Our ratio of current assets to current liabilities was 0.661.51 to 1.0 at September 30, 20172019 as compared to 0.731.04 to 1.0 at December 31, 2016.

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 are beyond our ability to control or predict. During the nine months ended September 30, 2017, we received an average of $46.34per Bbl of oil and $2.96per Mcf of natural gas before consideration of commodity derivative contracts compared to $37.75per Bbl of oil and $1.97per Mcf of natural gas in the nine months ended September 30, 2016. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business.

2018.

54


Critical Accounting Policies, Practices and Estimates

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

In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets, valuation of stock-based compensation, valuation of business combinations, accounting and valuation of nonmonetary exchanges,transactions, litigation and environmental contingencies, valuation of financial derivative instruments, valuation of stock-based compensationuncertain tax positions and income taxes. Management’sIn addition to these areas, goodwill impairment is also considered a critical estimate and is discussed below.
Goodwill impairment. 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, which includes a control premium, and the fair value of our long-term debt). There is considerable judgment involved in estimating fair values, particularly in determining the control premium. To establish a reasonable control premium, we considered the premiums paid in recent market acquisitions and analyzed 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.
In addition to our annual goodwill impairment test at July 1, we performed an impairment test at August 29, 2019, as discussed in Note 2 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)", and at September 30, 2019 due to the recent decline in the Company’s market capitalization during the third quarter of 2019. The fair value of the reporting unit at September 30, 2019 exceeded the carrying value of our net assets.
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 our enterprise value is a continued depressed level of the Company's stock price. At September 30, 2019, the average stock price we used in determining our market capitalization was $71.61. Further declines in our average stock price could result in an impairment of goodwill. For example, leaving the control premium and all other factors constant, an average stock price of approximately $61.50 at September 30, 2019 would have resulted in the impairment of our entire goodwill balance, while an average stock price between approximately $61.50 and $70.00 would have resulted in a partial impairment of our goodwill balance. Many factors affecting the Company's 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 would 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, 3 and 6 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding goodwill.
Management's judgments and estimates in theseall the areas listed above are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.

There have been no material changes, except the one discussed above, in our critical accounting policies and procedures during the nine months ended September 30, 2017.2019. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2016,2018, filed with the United States Securities and Exchange Commission (the “SEC”(“SEC”) on February 22, 2017.

20, 2019.

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

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral See Note 2 of the Effective Date,Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” which deferred the effective date of ASU No. 2014-09 by one year. Thatfor information regarding new standard is now effective for annual reporting periods beginning after December 15, 2017. We expect to use the modified retrospective method to adopt the standard, meaning the cumulative effect of initially applying the standard will be recognized with an adjustment to retained earnings on January 1, 2018. We have substantially completed our internal evaluation of the adoption of this standard, which included a review of all revenue-related contracts with customers and the application of the new revenue recognition model against those contracts. We are also updating our revenue recognition policy to conform to the new standard. We also expect to expand our revenue recognition related disclosure. Including those changes previously discussed, we doaccounting pronouncements issued but not expect this new guidance will have a material impact on our consolidated financial statements.

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

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

yet adopted.

55


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

56

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2016.

2018.

We are exposed to a variety of market risks, including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we are a party atSeptember 30, 20172019, 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 AgreementsAgreements”) with each of our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set-off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.See Note 7 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative activities.

Commodity price risk. risk.We are exposed to market risk as the prices of our commodities are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of our commodities, we have entered into, and may in the future enter into, additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Our commodity price risk management arrangements are recorded at fair value and thus changes to the future commodity prices will have an impact on net income.our earnings. The following table sets forth the hypothetical impact on the fair value of the commodity price risk management arrangements from an average increase and decrease in the commodity price of $5.00 per Bbl of oil and $0.50 per MMBtu of natural gas from the commodity prices at September 30, 2017:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Increase of

 

 

Decrease of

 

 

 

 

 

 

 

 

$5.00 per Bbl and

 

 

$5.00 per Bbl and

(in millions)

 

$0.50 per MMBtu

 

 

$0.50 per MMBtu

 

 

 

 

 

 

 

 

 

 

 

 

 Gain (loss):

 

 

 

 

 

 

Oil derivatives

$

(289)

 

$

289

 

Natural gas derivatives

 

(31)

 

 

31

 

 

Total

$

(320)

 

$

320

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2019:

57

(in millions)Increase of
$5.00 per Bbl and
$0.50 per MMBtu		 Decrease of
$5.00 per Bbl and
$0.50 per MMBtu
Gain (loss):   
Oil derivatives$(387) $388
Natural gas derivatives(99) 99
Total$(486) $487
    

At September 30, 2017,2019, we had (i) oil price swaps that settle on a monthly basisand oil costless collars covering future oil production from October 1, 20172019 through December 31, 20192021 and (ii) oil basis swaps covering our Midland to Cushing basis differential from October 1, 20172019 to December 31, 2019.2021. The average NYMEX oil price for the nine months ended at September 30, 20172019 was $49.45$54.07 per Bbl. At October 30, 2017,28, 2019, the NYMEX oil price was $54.15$55.81 per Bbl.

At September 30, 20172019, we had (i) natural gas price swaps that settle on a monthly basis covering future natural gas production from October 1,, 2017 2019 to December 31, 2021 and (ii) natural gas basis swaps covering our El Paso Permian to Henry Hub and WAHA to Henry Hub basis differentials from October 1, 2019. to December 31, 2021. The average NYMEX natural gas price for the nine months ended at September 30, 20172019 was $3.06 $2.33 per MMBtu. At October 30, 2017,28, 2019, the NYMEX natural gas price was $2.97$2.45 per MMBtu.

A decrease

An increase in the average forward NYMEX oil and natural gas prices belowabove those at September 30, 20172019 would decrease the fair value liabilityasset of our commodity derivative contracts from their recorded balance at September 30, 20172019. Changes in the recorded fair value of our commodity derivative contracts are marked to market through earnings as gains or losses. The potential decrease in our fair value liabilityasset would be recorded in earnings as a gain.loss. However, an increasea decrease in the average forward NYMEX oil and natural gas prices abovebelow those at September 30, 20172019 would increase the fair value liabilityasset of our commodity derivative contracts from their recorded balance at September 30, 20172019. The potential increase in our fair value liabilityasset 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 $445 million and $793 million for the nine months ended September 30, 2019 and 2018, respectively. The decrease in loss on derivatives was primarily due to the change in commodity future price curves at the respective measurement and settlement periods.
The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method for our derivative instruments during the nine months ended September 30, 20172019. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the nine months ended September 30, 20172019:

Commodity Derivative

Instruments

(in millions)

Net Assets (Liabilities) (a)

 Fair value of contracts outstanding at December 31, 2016

 $  

(174)

Changes in fair values (b)

289

Contract maturities

(126)

Fair value of contracts outstanding at September 30, 2017

$

(11)

(a)

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

(b)

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

(in millions)
Commodity Derivative Instruments
Net Assets (Liabilities)
Fair value of contracts outstanding at December 31, 2018$695
Changes in fair values (a)(445)
Contract maturities57
Fair value of contracts outstanding at September 30, 2019 (b)$307
  
(a) At inception, new derivative contracts entered into by us have no intrinsic value.
(b) Represents the fair value of open derivative contracts subject to market risk.
See Note 7 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments.

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

We had total indebtedness of $368$395 million outstanding under our credit facilityCredit Facility at September 30, 20172019. The impact of a one percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $4$4 million.

58


Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. Procedures.As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at September 30, 20172019 at the reasonable assurance level.

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

59


PART II – OTHER INFORMATION

Item 1.  Legal Proceedings

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

Item 1A.  Risk Factors

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


There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2016,2018, other than updating the risk factoras set forth below. The risks described in
We cannot guarantee that our Annual Report on Form 10-K for the year ended December 31, 2016 and in this Quarterly Report are not the only risks we face. Additional risks and uncertainties not currently known to usrecently announced share repurchase program will be fully consummated or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. The updated risk factor is as follows:

Future price declines could result in a reduction insuch program will enhance the carryinglong-term value of our proved oilcommon stock.


In September 2019, we announced that our board of directors authorized the initiation of a $1.5 billion share repurchase program. We expect to fund the 2019 repurchases with proceeds from our New Mexico Shelf divestiture, which is expected to close in November 2019. The Company is under no obligation to repurchase any specific dollar amount of common stock, and natural gas properties, which could adversely affectthe repurchase program may be extended, suspended or discontinued at any time by our resultsboard of operations.

Declines in commodity prices may result in us having to make substantial downward adjustments todirectors. As such, we cannot guarantee that this program will be fully consummated, or that such program will enhance the long-term value of our estimated proved reserves. If this occurs, or ifcommon stock. The extent to which we repurchase our estimatescommon stock and the timing and funding of production or economicsuch repurchases are dependent upon a variety of 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) prevailingincluding 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.

Based on economic factors at September 30, 2017, we determined that undiscounted future cash flows attributable to our NBBS field with a net book value of approximately $1.1 billion indicated that its carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows) subsequent to September 30, 2017. We estimate that if the oil and natural gas prices used in the estimated fair value analysis would have been approximately 10 percent lower at September 30, 2017 with no other changes in capital costs, operating costs, price differentials, or reserve performance curves, we could have recognized a non-cash impairment in that period of approximately $470 million related to our NBBS field. Other assumptions such as operating costs, well and reservoir performance, severance and ad valorem taxes, and operating and development plans would likely change given a change in oil and natural gas prices. However, we are unable to estimate the correlation between these assumptions and any estimated commodity price change, and theseconditions, regulatory requirements and other assumptions may worsen or partially mitigate somecorporate considerations, as determined by our management and board of the effects of a reduction in commodity prices, including the ultimate impact and amount of any potential impairment charge. As a result, we are unable to predict with certainty whether or not a decline in commodity prices alone will cause us to recognize an impairment charge in a particular field or the magnitude of any such impairment charge.

directors.

60


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

 

 

 

 

 

 

 

 

 

 

 

Period

 

Total number of shares withheld (a)

 

Average price per share

 

Total number of shares purchased as part of publicly announced plans

 

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

 

 

 

 

 

 

 

 

 

 

 

July 1, 2017 - July 31, 2017

  

585

 

$

121.87

 

-

 

 

August 1, 2017 - August 31, 2017

  

5,103

 

$

116.37

 

-

 

 

September 1, 2017 - September 30, 2017

  

213

 

$

123.73

 

-

 

 

  

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

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

 

  

  

 

 

 

 

 

 

 

 

 

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

61

Period
Total number of shares
withheld (1)
Average price per share
Total number of shares
purchased as part of
publicly announced plans
Maximum dollar value of
shares that may yet be
purchased under the plan (2)
(in millions)
July 1, 2019 - July 31, 20196,065
$99.88
—
—
August 1, 2019 - August 31, 201919
$71.94
—
—
September 1, 2019 - September 30, 2019135
$73.52
—
$1,500
     
(1) Represents shares that were withheld by us to satisfy tax withholding obligations of certain employees that arose upon the lapse of restrictions on share-based awards.
(2) In September 2019, we announced that our board of directors authorized the initiation of a common share repurchase program for up to $1.5 billion of our common stock. The program does not have a stated expiration date.


Item 6.  Exhibits

Exhibit

 Number 

Exhibit

Exhibit No.

Exhibit

3.1

3.1

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

3.2

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

4.131.1

(a) 

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

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).

4.3

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).

4.4

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

4.5

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

31.1

 (a)

Certification of Chief Executive Officer pursuant to Section 302 ofRule 13a-14(a) under the Sarbanes-OxleySecurities Exchange Act of 2002.

1934.

31.2

(a)

Certification of Chief Financial Officer pursuant to Section 302 ofRule 13a-14(a) under the Sarbanes-OxleySecurities Exchange Act of 2002.

1934.

32.1

(b)

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

1350.

32.2

(b)

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

1350.

101.INS

(a)

XBRL Instance Document.

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

101.SCH

(a)

Inline XBRL Schema Document.

101.CAL

(a)

Inline XBRL Calculation Linkbase Document.

101.DEF

(a)

Inline XBRL Definition Linkbase Document.

101.LAB

(a)

Inline XBRL Labels Linkbase Document.

101.PRE

(a)

Inline XBRL Presentation Linkbase Document.

104

(a)

The cover page of Concho Resources Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2019, formatted in Inline XBRL and included within the Exhibit 101 attachments.
(a) Filed herewith.
(b) Furnished herewith.

(a)  Filed herewith.

(b)  Furnished herewith.


62

SIGNATURES

SIGNATURES

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

CONCHO RESOURCES INC.

Date:

November 1, 2017

October 30, 2019

By

By

/s/  Timothy A. Leach

Timothy A. Leach

Chairman of the Board of Directors and Chief Executive

Executive Officer

(Principal Executive Officer)

By

By

/s/  Jack F. Harper

Jack F. Harper

President and Chief Financial Officer

(Principal Financial Officer)

By

/s/  Brenda R. Schroer

Brenda R. Schroer

Senior Vice President, Chief AccountingFinancial Officer and Treasurer

Treasurer

(Principal Financial Officer)
By/s/  Jacob P. Gobar
Jacob P. Gobar
Vice President and Chief Accounting Officer
(Principal Accounting Officer)

63


55