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CHESAPEAKE ENERGY CORP - Quarter Report: 2018 September (Form 10-Q)



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X]    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2018
[  ]    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File No. 1-13726
CHESAPEAKE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Oklahoma
 
73-1395733
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
6100 North Western Avenue, Oklahoma City, Oklahoma
 
73118
(Address of principal executive offices)
 
(Zip Code)
(405) 848-8000
(Registrant’s telephone number, including area code)
 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X]     NO [ ] 
 
 Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). YES [X]     NO [ ]
 
 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large Accelerated Filer [X] Accelerated Filer [ ] Non-accelerated Filer [ ]
Smaller Reporting Company [ ] Emerging Growth Company [ ]
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES [ ]      NO [X]
As of October 25, 2018, there were 913,710,098 shares of our $0.01 par value common stock outstanding.





CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2018


 
PART I. FINANCIAL INFORMATION
Page
Item 1.
 
 
September 30, 2018 and December 31, 2017
 
for the Three and Nine Months Ended September 30, 2018 and 2017
 
for the Three and Nine Months Ended September 30, 2018 and 2017
 
for the Nine Months Ended September 30, 2018 and 2017
 
for the Nine Months Ended September 30, 2018 and 2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
Item 3.
Item 4.
 
PART II. OTHER INFORMATION
 
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
 
 
 
 

Table of Contents
PART I. FINANCIAL INFORMATION



ITEM 1.
Condensed Consolidated Financial Statements

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
 
September 30,
2018
 
December 31, 2017
 
 
($ in millions)
CURRENT ASSETS:
 
 
 
 
Cash and cash equivalents ($1 and $2 attributable to our VIE)
 
$
4

 
$
5

Accounts receivable, net
 
1,051

 
1,322

Short-term derivative assets
 
—

 
27

Other current assets
 
180

 
171

Total Current Assets
 
1,235

 
1,525

PROPERTY AND EQUIPMENT:
 
 
 
 
Oil and natural gas properties, at cost based on full cost accounting:
 
 
 
 
Proved oil and natural gas properties
($488 and $488 attributable to our VIE)
 
70,620

 
68,858

Unproved properties
 
3,198

 
3,484

Other property and equipment
 
1,812

 
1,986

Total Property and Equipment, at Cost
 
75,630

 
74,328

Less: accumulated depreciation, depletion and amortization
(($463) and ($461) attributable to our VIE)
 
(64,500
)
 
(63,664
)
Property and equipment held for sale, net
 
47

 
16

Total Property and Equipment, Net
 
11,177

 
10,680

LONG-TERM ASSETS:
 
 
 
 
Other long-term assets
 
247

 
220

TOTAL ASSETS
 
$
12,659

 
$
12,425

 
 
 
 
 

The accompanying notes are an integral part of these condensed consolidated financial statements.
3
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS – (Continued)
(Unaudited)

 
 
September 30,
2018
 
December 31, 2017
 
 
($ in millions)
CURRENT LIABILITIES:
 
 
 
 
Accounts payable
 
$
670

 
$
654

Current maturities of long-term debt, net
 
432

 
52

Accrued interest
 
126

 
137

Short-term derivative liabilities
 
310

 
58

Other current liabilities ($2 and $3 attributable to our VIE)
 
1,438

 
1,455

Total Current Liabilities
 
2,976

 
2,356

LONG-TERM LIABILITIES:
 
 
 
 
Long-term debt, net
 
9,380

 
9,921

Long-term derivative liabilities
 
28

 
4

Asset retirement obligations, net of current portion
 
154

 
162

Other long-term liabilities
 
160

 
354

Total Long-Term Liabilities
 
9,722

 
10,441

CONTINGENCIES AND COMMITMENTS (Note 4)
 

 

EQUITY:
 
 
 
 
Chesapeake Stockholders’ Equity (Deficit):
 
 
 
 
Preferred stock, $0.01 par value, 20,000,000 shares authorized:
5,603,458 shares outstanding
 
1,671

 
1,671

Common stock, $0.01 par value, 2,000,000,000 shares authorized:
913,691,662 and 908,732,809 shares issued
 
9

 
9

Additional paid-in capital
 
14,394

 
14,437

Accumulated deficit
 
(16,173
)
 
(16,525
)
Accumulated other comprehensive loss
 
(32
)
 
(57
)
Less: treasury stock, at cost;
3,307,953 and 2,240,394 common shares
 
(31
)
 
(31
)
Total Chesapeake Stockholders’ Equity (Deficit)
 
(162
)
 
(496
)
Noncontrolling interests
 
123

 
124

Total Equity (Deficit)
 
(39
)
 
(372
)
TOTAL LIABILITIES AND EQUITY
 
$
12,659

 
$
12,425


The accompanying notes are an integral part of these condensed consolidated financial statements.
4
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
  
 
($ in millions except per share data)
REVENUES:
 
 
 
 
 
 
 
 
Oil, natural gas and NGL
 
$
1,199

 
$
979

 
$
3,424

 
$
3,727

Marketing
 
1,219

 
964

 
3,738

 
3,250

Total Revenues
 
2,418

 
1,943

 
7,162

 
6,977

OPERATING EXPENSES:
 
 
 
 
 
 
 
 
Oil, natural gas and NGL production
 
132

 
151

 
417

 
426

Oil, natural gas and NGL gathering, processing and transportation
 
364

 
369

 
1,060

 
1,081

Production taxes
 
34

 
21

 
91

 
64

Marketing
 
1,238

 
978

 
3,798

 
3,333

General and administrative
 
66

 
54

 
229

 
189

Restructuring and other termination costs
 
—

 
—

 
38

 
—

Provision for legal contingencies, net
 
8

 
20

 
17

 
35

Oil, natural gas and NGL depreciation, depletion and amortization
 
274

 
228

 
813

 
627

Depreciation and amortization of other assets
 
17

 
20

 
54

 
62

Impairments
 
5

 
3

 
51

 
3

Other operating (income) expense
 
—

 
6

 
(1
)
 
423

Net (gains) losses on sales of fixed assets
 
—

 
(1
)
 
7

 
—

Total Operating Expenses
 
2,138

 
1,849

 
6,574

 
6,243

INCOME FROM OPERATIONS
 
280

 
94

 
588

 
734

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
 
Interest expense
 
(127
)
 
(114
)
 
(367
)
 
(302
)
Gains on investments
 
—

 
—

 
139

 
—

Gains (losses) on purchases or exchanges of debt
 
(68
)
 
(1
)
 
(68
)
 
183

Other income
 
1

 
4

 
63

 
6

Total Other Expense
 
(194
)
 
(111
)
 
(233
)
 
(113
)
INCOME (LOSS) BEFORE INCOME TAXES
 
86

 
(17
)
 
355

 
621

Income tax expense (benefit)
 
1

 
—

 
(8
)
 
2

NET INCOME (LOSS)
 
85

 
(17
)
 
363

 
619

Net income attributable to noncontrolling interests
 
(1
)
 
(1
)
 
(3
)
 
(3
)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
 
84

 
(18
)
 
360

 
616

Preferred stock dividends
 
(23
)
 
(23
)
 
(69
)
 
(62
)
Loss on exchange of preferred stock
 
—

 
—

 
—

 
(41
)
Earnings allocated to participating securities
 
(1
)
 
—

 
(3
)
 
(7
)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS
 
$
60

 
$
(41
)
 
$
288

 
$
506

EARNINGS (LOSS) PER COMMON SHARE:
 
 
 
 
 
 
 
 
Basic
 
$
0.07

 
$
(0.05
)
 
$
0.32

 
$
0.56

Diluted
 
$
0.07

 
$
(0.05
)
 
$
0.32

 
$
0.56

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
 
 
 
 
 
 
 
 
Basic
 
910

 
909

 
909

 
908

Diluted
 
911

 
909

 
909

 
908


The accompanying notes are an integral part of these condensed consolidated financial statements.
5
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)



 
 
Three Months Ended September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
($ in millions)
NET INCOME (LOSS)
 
$
85

 
$
(17
)
 
$
363

 
$
619

OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:
 
 
 
 
 
 
 
 
Unrealized gains on derivative instruments(a)
 
—

 
—

 
—

 
4

Reclassification of losses on settled derivative instruments(a)
 
8

 
8

 
25

 
25

Other Comprehensive Income
 
8

 
8

 
25

 
29

COMPREHENSIVE INCOME (LOSS)
 
93

 
(9
)
 
388

 
648

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
(1
)
 
(1
)
 
(3
)
 
(3
)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
 
$
92

 
$
(10
)
 
$
385

 
$
645

___________________________________________
(a)
Deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.


The accompanying notes are an integral part of these condensed consolidated financial statements.
6
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

 
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
 
($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
NET INCOME
 
$
363

 
$
619

ADJUSTMENTS TO RECONCILE NET INCOME TO CASH
PROVIDED BY (USED IN) OPERATING ACTIVITIES:
 
 
 
 
Depreciation, depletion and amortization
 
867

 
689

Derivative (gains) losses, net
 
500

 
(452
)
Cash payments on derivative settlements, net
 
(162
)
 
(46
)
Stock-based compensation
 
25

 
38

Net losses on sales of fixed assets
 
7

 
—

Impairments
 
51

 
3

Gains on investments
 
(139
)
 
—

(Gains) losses on purchases or exchanges of debt
 
68

 
(185
)
Other
 
(101
)
 
(27
)
Changes in assets and liabilities
 
116

 
(366
)
Net Cash Provided By Operating Activities
 
1,595

 
273

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
Drilling and completion costs
 
(1,481
)
 
(1,597
)
Acquisitions of proved and unproved properties
 
(244
)
 
(226
)
Proceeds from divestitures of proved and unproved properties
 
395

 
1,193

Additions to other property and equipment
 
(11
)
 
(12
)
Proceeds from sales of other property and equipment
 
75

 
40

Proceeds from sales of investments
 
74

 
—

Net Cash Used In Investing Activities
 
(1,192
)
 
(602
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
Proceeds from revolving credit facility borrowings
 
9,095

 
4,775

Payments on revolving credit facility borrowings
 
(9,231
)
 
(4,130
)
Proceeds from issuance of senior notes, net
 
1,237

 
742

Extinguishment of other financing
 
(122
)
 
—

Cash paid to purchase debt
 
(1,285
)
 
(1,751
)
Cash paid for preferred stock dividends
 
(69
)
 
(160
)
Distributions to noncontrolling interest owners
 
(4
)
 
(7
)
Other
 
(25
)
 
(17
)
Net Cash Used In Financing Activities
 
(404
)
 
(548
)
Net decrease in cash and cash equivalents
 
(1
)
 
(877
)
Cash and cash equivalents, beginning of period
 
5

 
882

Cash and cash equivalents, end of period
 
$
4

 
$
5

 
 
 
 
 
 

The accompanying notes are an integral part of these condensed consolidated financial statements.
7
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)
(Unaudited)

Supplemental disclosures to the consolidated statements of cash flows are presented below:
 
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
 
($ in millions)
SUPPLEMENTAL CASH FLOW INFORMATION:
 
 
 
 
Interest paid, net of capitalized interest
 
$
412

 
$
342

Income taxes paid, net of refunds received
 
$
(3
)
 
$
(15
)
 
 
 
 
 
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
 
 
 
 
Change in accrued drilling and completion costs
 
$
165

 
$
134

Change in accrued acquisitions of proved and unproved properties
 
$
1

 
$
(1
)
Change in divested proved and unproved properties
 
$
(5
)
 
$
(23
)


The accompanying notes are an integral part of these condensed consolidated financial statements.
8
TABLE OF CONTENTS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Unaudited)




 
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
 
($ in millions)
PREFERRED STOCK:
 
 
 
 
Balance, beginning of period
 
$
1,671

 
$
1,771

Exchange/conversions of 0 and 236,048 shares of preferred stock for common stock
 
—

 
(100
)
Balance, end of period
 
1,671

 
1,671

COMMON STOCK:
 
 
 
 
Balance, beginning and end of period
 
9

 
9

ADDITIONAL PAID-IN CAPITAL:
 
 
 
 
Balance, beginning of period
 
14,437

 
14,486

Stock-based compensation
 
26

 
43

Exchange of preferred stock for 0 and 9,965,835 shares of common stock
 
—

 
100

Equity component of contingent convertible notes repurchased, net of tax
 
—

 
(20
)
Dividends on preferred stock
 
(69
)
 
(160
)
Balance, end of period
 
14,394

 
14,449

RETAINED EARNINGS (ACCUMULATED DEFICIT):
 
 
 
 
Balance, beginning of period
 
(16,525
)
 
(17,603
)
Net income attributable to Chesapeake
 
360

 
616

Cumulative effect of accounting change
 
(8
)
 
—

Balance, end of period
 
(16,173
)
 
(16,987
)
ACCUMULATED OTHER COMPREHENSIVE LOSS:
 
 
 
 
Balance, beginning of period
 
(57
)
 
(96
)
Hedging activity
 
25

 
29

Balance, end of period
 
(32
)
 
(67
)
TREASURY STOCK – COMMON:
 
 
 
 
Balance, beginning of period
 
(31
)
 
(27
)
Purchase of 1,499,033 and 1,194,986 shares for company benefit plans
 
(4
)
 
(7
)
Release of 431,474 and 92,015 shares from company benefit plans
 
4

 
2

Balance, end of period
 
(31
)
 
(32
)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT)
 
(162
)
 
(957
)
NONCONTROLLING INTERESTS:
 
 
 
 
Balance, beginning of period
 
124

 
257

Net income attributable to noncontrolling interests
 
3

 
3

Distributions to noncontrolling interest owners
 
(4
)
 
(7
)
Balance, end of period
 
123

 
253

TOTAL EQUITY (DEFICIT)
 
$
(39
)
 
$
(704
)

The accompanying notes are an integral part of these condensed consolidated financial statements.
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


1.
Basis of Presentation
Basis of Presentation
The accompanying condensed consolidated financial statements of Chesapeake were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules and regulations of the SEC. Pursuant to such rules and regulations, certain disclosures have been condensed or omitted.
This Form 10-Q relates to the three and nine months ended September 30, 2018 (the “Current Quarter” and the “Current Period”, respectively) and the three and nine months ended September 30, 2017 (the “Prior Quarter” and the “Prior Period”, respectively). Our annual report on Form 10-K for the year ended December 31, 2017 (“2017 Form 10-K”) should be read in conjunction with this Form 10-Q. The accompanying condensed consolidated financial statements reflect all normal recurring adjustments which, in the opinion of management, are necessary for a fair statement of our condensed consolidated financial statements and accompanying notes and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which we have a controlling financial interest. Intercompany accounts and balances have been eliminated.
Recently Issued Accounting Standards
The Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers (Topic 606) superseding virtually all existing revenue recognition guidance. We adopted this new standard in the first quarter of 2018 using the modified retrospective approach. We applied the new standard to all contracts that were not completed as of January 1, 2018 and reflected the aggregate effect of all modifications in determining and allocating the transaction price. See Note 10 for further details regarding our adoption of Topic 606.
In February 2018, the FASB issued Accounting Standards Update (ASU) 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The new standard allows for stranded tax effects resulting from tax reform legislation known as the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) previously recognized in accumulated other comprehensive income to be reclassified to retained earnings. For public business entities, the amendments are effective for annual periods, including interim periods within the annual periods, beginning after December 15, 2018. Early adoption is permitted in any interim or annual period, but we do not plan to early adopt. We are currently evaluating the impact of this standard on our consolidated financial statements and related disclosures.
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815), which makes significant changes to the current hedge accounting guidance. The new standard eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The new standard also eases certain documentation and assessment requirements and modifies the accounting for components excluded from the assessment of hedge effectiveness. The new standard update is effective for annual and interim periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted, but we do not plan to early adopt. We are currently evaluating the impact of this standard on our consolidated financial statements and related disclosures.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which updated lease accounting guidance requiring lessees to recognize most leases, including operating leases, on the balance sheet as a right-of-use asset and lease liability for leases with terms in excess of 12 months. In January 2018, the FASB issued ASU 2018-01 permitting an entity to elect an optional transition practical expedient to not evaluate land easements that existed or expired before the adoption of Topic 842 and were not previously accounted for as leases. In July 2018, the FASB issued ASU 2018-11 to provide an additional transition practical expedient by allowing entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We plan to elect both practical expedients. We plan to adopt the new standard on January 1, 2019 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings. The standard will not apply to our leases of mineral rights. Using the revised framework, we have completed our assessment of lease categories that we believe will be affected by the new standard. We are continuing to assess the accounting treatment for these leases but do not expect the adoption to have significant impacts to our consolidated financial statements or related disclosures.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

2.
Earnings Per Share
Basic earnings per share (EPS) is calculated using the weighted average number of common shares outstanding during the period and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide dividend rights.
Diluted EPS is calculated assuming the issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For all periods presented, our contingent convertible senior notes did not have a dilutive effect and, therefore, were excluded from the calculation of diluted EPS. See Note 3 for further discussion of our convertible senior notes and contingent convertible senior notes.
A reconciliation of basic EPS and diluted EPS is as follows:
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(in millions, except per share data)
Net income (loss) available to common stockholders
 
$
60

 
$
(41
)
 
$
288

 
$
506

Effect of dilutive securities
 
—

 
—

 
—

 
—

Diluted income (loss) available to common stockholders
 
$
60

 
$
(41
)
 
$
288

 
$
506

 
 
 
 
 
 
 
 
 
Weighted average common and common equivalent shares outstanding - basic
 
910

 
909

 
909

 
908

Effect of dilutive securities
 
1

 
—

 
—

 
—

Weighted average common and common equivalent shares outstanding - diluted
 
911

 
909

 
909

 
908

 
 
 
 
 
 
 
 
 
Net income per share attributable to Chesapeake:
 
 
 
 
 
 
 
 
Basic
 
$
0.07

 
$
(0.05
)
 
$
0.32

 
$
0.56

Diluted
 
$
0.07

 
$
(0.05
)
 
$
0.32

 
$
0.56

 
 
 
 
 
 
 
 
 
Shares of common stock for the following securities were excluded from the calculation of diluted EPS as the effect was antidilutive:
 
 
 
 
 
 
 
 
Common stock equivalent of our preferred stock outstanding
 
60

 
60

 
60

 
60

Common stock equivalent of our convertible senior notes outstanding
 
146

 
146

 
146

 
146

Participating securities
 
2

 
—

 
1

 
1



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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

3.
Debt
Our long-term debt consisted of the following as of September 30, 2018 and December 31, 2017:
 
September 30, 2018
 
December 31, 2017
 
Principal
Amount
 
Carrying
Amount
 
Principal
Amount
 
Carrying
Amount
 
($ in millions)
7.25% senior notes due 2018
$
44

 
$
44

 
$
44

 
$
44

Floating rate senior notes due 2019
380

 
380

 
380

 
380

6.625% senior notes due 2020
437

 
437

 
437

 
437

6.875% senior notes due 2020
227

 
227

 
227

 
227

6.125% senior notes due 2021
548

 
548

 
548

 
548

5.375% senior notes due 2021
267

 
267

 
267

 
267

4.875% senior notes due 2022
451

 
451

 
451

 
451

8.00% senior secured second lien notes due 2022(a)
1,416

 
1,823

 
1,416

 
1,895

5.75% senior notes due 2023
338

 
338

 
338

 
338

7.00% senior notes due 2024
850

 
850

 
—

 
—

8.00% senior notes due 2025
1,300

 
1,290

 
1,300

 
1,290

5.5% convertible senior notes due 2026(b)(c)
1,250

 
859

 
1,250

 
837

7.5% senior notes due 2026
400

 
400

 
—

 
—

8.00% senior notes due 2027
1,300

 
1,298

 
1,300

 
1,298

2.25% contingent convertible senior notes due 2038(b)
9

 
8

 
9

 
8

Term loan due 2021
—

 
—

 
1,233

 
1,233

Revolving credit facility
645

 
645

 
781

 
781

Debt issuance costs
—

 
(54
)
 
—

 
(63
)
Interest rate derivatives
—

 
1

 
—

 
2

Total debt, net
9,862

 
9,812

 
9,981

 
9,973

Less current maturities of long-term debt, net(d)
(433
)
 
(432
)
 
(53
)
 
(52
)
Total long-term debt, net
$
9,429

 
$
9,380

 
$
9,928

 
$
9,921

___________________________________________
(a)
On October 29, 2018, we delivered a notice of redemption to the trustee with respect to 100% of the aggregate principal amount of the outstanding senior secured second lien notes dues 2022.
(b)
We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense through the first demand repurchase date, as applicable, at the interest rate of similar nonconvertible debt at the time of issuance. The applicable rates for our 2.25% Contingent Convertible Senior Notes due 2038 and our 5.5% Convertible Senior Notes due 2026 are 8.0% and 11.5%, respectively.
(c)
Prior to maturity under certain circumstances and at the holder’s option, the notes are convertible. During the Current Quarter, the price of our common stock was below the threshold level for conversion and, as a result, the holders do not have the option to convert their notes in the fourth quarter of 2018.
(d)
As of September 30, 2018, net current maturities of long-term debt includes our 7.25% Senior Notes due December 2018, our Floating Rate Senior Notes due April 2019, and due to the holders’ put option, our 2.25% Contingent Convertible Notes due December 2038.    

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

Debt Issuances and Retirements
In the Current Quarter, we issued at par $850 million of 7.00% Senior Notes due 2024 (“2024 notes”) and $400 million of 7.50% Senior Notes due 2026 (“2026 notes”) pursuant to a public offering for net proceeds of $1.230 billion. We used the net proceeds from the senior notes, together with cash on hand and borrowings under our revolving credit facility, to repay in full $1.233 billion of borrowings under our secured term loan due 2021 for $1.285 billion, which included a $52 million call premium. We recorded a loss of approximately $65 million associated with the repayment of the term loan, including the call premium and the write-off of $13 million of associated deferred charges.
We may redeem some or all of the 2024 notes at any time prior to April 1, 2021 and some or all of the 2026 notes at any time prior to October 1, 2021, in each case at a price equal to 100% of the principal amount of the notes to be redeemed plus a “make-whole” premium. At any time prior to April 1, 2021, with respect to the 2024 notes, and October 1, 2021, with respect to the 2026 notes, we also may redeem up to 35% of the aggregate principal amount of each series of notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a specified redemption price. In addition, we may redeem some or all of the 2024 notes at any time on or after April 1, 2021 and some or all of the 2026 notes at any time on or after October 1, 2021, in each case at the redemption prices in accordance with the terms of the notes and the indenture and supplemental indenture governing the notes. These senior notes are unsecured obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Our obligations under the senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect wholly owned subsidiaries.
In the Prior Period, we retired $1.609 billion principal amount of our outstanding senior notes, senior secured second lien notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $1.751 billion. For the open market repurchases and tender offers, we recorded an aggregate net loss of approximately $1 million in the Prior Quarter and an aggregate gain of approximately $183 million in the Prior Period including $260 million of premium associated with our 8.00% Senior Secured Second Lien Notes due 2022.
Revolving Credit Facility
On September 12, 2018, we amended and restated our credit agreement dated December 15, 2014. The amended and restated revolving credit facility matures in September 2023 and the aggregate initial commitment of the lenders and borrowing base under the facility is $3.0 billion. The revolving credit facility provides for an accordion feature, pursuant to which the aggregate commitments thereunder may be increased to up to $4.0 billion from time to time, subject to agreement of the participating lenders and certain other customary conditions. Borrowing base redeterminations will continue to occur semiannually and our next borrowing base redetermination is scheduled for the second quarter of 2019. As of September 30, 2018, we had outstanding borrowings of $645 million under the revolving credit facility and had used $182 million of the revolving credit facility for various letters of credit. We recorded a loss of $3 million associated with certain deferred charges related to the revolving credit facility prior to this amendment.
Borrowings under the revolving credit facility bear interest at an alternative base rate (ABR) or LIBOR, at our election, plus an applicable margin ranging from0.50%-2.00% per annum for ABR loans and 1.50%-3.00% per annum for LIBOR loans, depending on the percentage of the borrowing base then being utilized and whether our leverage ratio exceeds 4.00 to 1.
Our revolving credit facility is subject to various financial and other covenants. The terms of the revolving credit facility include covenants limiting, among other things, our ability to incur additional indebtedness, make investments or loans, incur liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates. Our revolving credit facility contains financial covenants that, after a transition period and the suspension of most of the covenants during the fourth quarter of 2018 as a result of the closing of the sale of certain of our Utica Shale properties pursuant to our purchase and sale agreement with EAP Ohio, LLC (“Encino”), requires the Company to maintain (i) a leverage ratio of not more than 5.50 to 1 through the fiscal quarter ending September 30, 2019, which threshold decreases over time to 4.00 to 1 for the fiscal quarter ending March 31, 2021 and each fiscal quarter thereafter, (ii) a secured leverage ratio of not more than 2.50 to 1 until the later of (x) the fiscal quarter ending March 31, 2021 or (y) the fiscal quarter in when the Company’s leverage ratio does not exceed 4.00 to 1 and (iii) a fixed charge coverage ratio of not less than 2.00 to 1 through the fiscal quarter ending December 31, 2019; not less than 2.25 to 1 through the fiscal quarter ending June 30, 2020; and not less than 2.50 to 1 for the fiscal quarter ended September 30, 2020 and thereafter. For the Current Quarter, we

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

were subject to the financial covenants applicable prior to the amended and restated revolving credit facility in addition to maintaining a leverage ratio of not more than 5.50 to 1.
As of September 30, 2018, we were in compliance with all applicable financial covenants under the credit agreement and we were able to borrow up to the full availability under the revolving credit facility.
Fair Value of Debt
We estimate the fair value of our senior notes based on the market value of our publicly traded debt as determined based on the yield of our senior notes (Level 1). The fair value of all other debt is based on a market approach using estimates provided by an independent investment financial data services firm (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below:
 
 
September 30, 2018
 
December 31, 2017
 
 
Carrying
Amount
 
Estimated
Fair Value
 
Carrying
Amount
 
Estimated
Fair Value
 
 
 
 
($ in millions)
 
 
Short-term debt (Level 1)
 
$
432

 
$
433

 
$
52

 
$
53

Long-term debt (Level 1)
 
$
3,495

 
$
3,546

 
$
2,633

 
$
2,629

Long-term debt (Level 2)
 
$
5,884

 
$
6,010

 
$
7,286

 
$
7,301

4.
Contingencies and Commitments
There have been no material developments in previously reported legal or environmental contingencies or commitments other than the items discussed below. For a discussion of commitments and contingencies, see “Contingencies and Commitments,” Note 4 to the Consolidated Financial Statements in our 2017 Form 10-K.
Contingencies
Regulatory and Related Proceedings. We have previously disclosed receiving U.S. Postal Service and state subpoenas seeking information on our royalty payment practices. The U.S. Postal Service inquiry and all such outstanding state subpoenas have been resolved.
We have also previously disclosed defending lawsuits alleging various violations of the Sherman Antitrust Act and state antitrust laws. In 2016, putative class action lawsuits were filed in the U.S. District Court for the Western District of Oklahoma and in Oklahoma state courts, and an individual lawsuit was filed in the U.S. District Court of Kansas, in each case against us and other defendants. The lawsuits generally allege that, since 2007 and continuing through April 2013, the defendants conspired to rig bids and depress the market for the purchases of oil and natural gas leasehold interests and properties in the Anadarko Basin containing producing oil and natural gas wells. The lawsuits seek damages, attorney’s fees, costs and interest, as well as enjoinment from adopting practices or plans that would restrain competition in a similar manner as alleged in the lawsuits. On April 12, 2018, we reached a tentative settlement to resolve substantially all Oklahoma civil class action antitrust cases for an immaterial amount.
On July 28, 2017, OOGC America LLC (OOGC) filed a demand for arbitration with the American Arbitration Association against Chesapeake Exploration, L.L.C., our wholly owned subsidiary, in connection with OOGC’s purchase of certain oil and gas leases and other assets pursuant to a Purchase and Sale Agreement entered into on October 10, 2010. In connection with the sale, we also entered into a Development Agreement with OOGC, dated November 15, 2010 (the “Development Agreement”), which governs each of our rights and obligations with respect to the sale, including the transportation and marketing of oil and gas. OOGC’s breach of contract, breach of agency and fiduciary duties and other claims generally allege, among other things, that we subjected OOGC to excessive rates for gathering and other services provided for under the Development Agreement and interfered with OOGC’s right to audit the documents that supported those rates. OOGC seeks relief that may be material, including unspecified damages, attorneys’ fees, costs and expenses, disgorgement and various declaratory judgments.  We intend to vigorously defend these claims.
On July 24, 2018, Healthcare of Ontario Pension Plan (HOOPP) filed a demand for arbitration with the American Arbitration Association regarding HOOPP’s purchase of our interest in Chaparral Energy, Inc. stock for $215 million on January 5, 2014. HOOPP claims that the Company engaged in material misrepresentations and fraud, and that we violated the Exchange Act and Oklahoma Uniform Securities Act. HOOPP seeks either rescission or $215 million in monetary damages, and in either case, interest, attorney’s fees, disgorgement and punitive damages. We intend to vigorously defend these claims.
Commitments
Gathering, Processing and Transportation Agreements
We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of oil, natural gas and NGL to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in our estimates of proved reserves.
The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below:
 
 
September 30,
2018
 
 
($ in millions)
2018
 
$
269

2019
 
1,048

2020
 
992

2021
 
900

2022
 
792

2023 – 2035
 
4,443

Total
 
$
8,444

In addition, we have entered into long-term agreements for certain natural gas gathering and related services within specified acreage dedication areas in exchange for cost-of-service based fees redetermined annually, or tiered fees based on volumes delivered relative to scheduled volumes. Future gathering fees may vary with the applicable agreement.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

5.
Other Liabilities
Other current liabilities as of September 30, 2018 and December 31, 2017 are detailed below:
 
 
September 30,
2018
 
December 31,
2017
 
 
($ in millions)
Revenues and royalties due others
 
$
535

 
$
612

Accrued drilling and production costs
 
313

 
216

Joint interest prepayments received
 
81

 
74

Accrued compensation and benefits
 
192

 
214

Other accrued taxes
 
123

 
43

Other
 
194

 
296

Total other current liabilities
 
$
1,438

 
$
1,455

Other long-term liabilities as of September 30, 2018 and December 31, 2017 are detailed below:
 
 
September 30,
2018
 
December 31,
2017
 
 
($ in millions)
CHK Utica ORRI conveyance obligation(a)
 
$
—

 
$
156

Unrecognized tax benefits
 
53

 
101

Other
 
107

 
97

Total other long-term liabilities
 
$
160

 
$
354

____________________________________________
(a)
In the Current Period, we repurchased previously conveyed overriding royalty interests (ORRI) from the CHK Utica, L.L.C. investors and extinguished our obligation to convey future ORRIs to the CHK Utica, L.L.C. investors for combined consideration of $199 million. The total CHK Utica ORRI conveyance obligation extinguished in the Current Period was $183 million, of which, $30 million was recorded in current liabilities and $153 million was recorded in long-term liabilities. The fair value of the consideration allocated to the extinguishment of liability, $122 million, was less than the carrying amount of the conveyance obligation and resulted in a gain of $61 million recognized in other income on our condensed consolidated statement of operations. The fair value of the consideration allocated to the purchase of ORRIs on proved producing properties was $77 million and recorded in proved oil and natural gas properties in our condensed consolidated balance sheet.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

6.
Income Taxes
We estimate our annual effective tax rate for continuing operations in recording our quarterly income tax provision (or benefit) for the various jurisdictions in which we operate. The tax effects of statutory rate changes, significant unusual or infrequent items, and certain changes in the assessment of the realizability of deferred tax assets are excluded from the determination of our estimated annual effective tax rate as such items are recognized as discrete items in the quarter in which they occur.
For the Current Quarter, our estimated annual effective tax rate remains nominal as a result of having a full valuation allowance against our net deferred tax asset. Taking into account our projected operating results for the subsequent 2018 quarter, we project remaining in a net deferred tax asset position as of December 31, 2018. Based on all available positive and negative evidence, including estimates of future taxable income, we believe it is more-likely-than-not that these deferred tax assets will not be realized. A significant piece of objectively verifiable negative evidence evaluated is the cumulative loss incurred over the rolling three-year period ending September 30, 2018. Such evidence limits our ability to consider various forms of subjective positive evidence, such as our projections for future growth and earnings. A valuation allowance was recorded against substantially all of our net deferred tax asset as of December 31, 2017 and against all of our net deferred tax asset as of September 30, 2018.
We are subject to U.S. federal income tax as well as income and capital taxes in various state jurisdictions in which we operate. We recorded a $1 million income tax expense in the Current Quarter and an $8 million income tax benefit in the Current Period. The $1 million expense in the Current Quarter was a result of discrete items related to additional state income tax expense for the settlement of a state income tax audit and the filing of amended state income tax returns. The $8 million benefit in the Current Period was a result of discrete items consisting of a $13 million reduction to the liability for state unrecognized tax benefits due to the expiration of applicable statutes of limitations which was partially offset by eliminating a deferred tax asset for alternative minimum tax carryforwards in the amount of $3 million and recording additional state income tax expense of $2 million relating primarily to the settlement of a state income tax audit and the filing of amended state income tax returns. A further reduction to the liability for state unrecognized tax benefits was also recorded against interest expense in the amount of $4 million.
On December 22, 2017, the President of the United States signed into law the Tax Act, which substantially revised numerous areas of U.S. federal income tax law, including reducing the tax rate for corporations from a maximum rate of 35% to a flat rate of 21% and eliminating the corporate alternative minimum tax (AMT). The various estimates included in determining our tax provision as of December 31, 2017 remain provisional through the nine months ended September 30, 2018 and may be adjusted through subsequent events such as the filing of the 2017 consolidated federal income tax return and the issuance of additional guidance such as new Treasury Regulations. Moreover, we are still in the process of evaluating the full impact of the Tax Act both at the federal and state level.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

7.
Share-Based Compensation
Our share-based compensation program consists of restricted stock, stock options, performance share units (PSUs) and cash restricted stock units (CRSUs) granted to employees and restricted stock granted to non-employee directors under our long term incentive plans. The restricted stock and stock options are equity-classified awards and the PSUs and CRSUs are liability-classified awards.
Equity-Classified Awards
Restricted Stock. We grant restricted stock units to employees and non-employee directors. A summary of the changes in unvested restricted stock during the Current Period is presented below:
 
 
Shares of
Unvested
Restricted Stock
 
Weighted Average
Grant Date
Fair Value Per Share
 
 
(in thousands)
 
 
Unvested restricted stock as of January 1, 2018
 
13,178

 
$
6.37

Granted
 
5,776

 
$
3.77

Vested
 
(5,782
)
 
$
7.67

Forfeited
 
(1,376
)
 
$
6.09

Unvested restricted stock as of September 30, 2018
 
11,796

 
$
4.49

The aggregate intrinsic value of restricted stock that vested during the Current Period was approximately $20 million based on the stock price at the time of vesting.
As of September 30, 2018, there was approximately $38 million of total unrecognized compensation expense related to unvested restricted stock. The expense is expected to be recognized over a weighted average period of approximately 2.12 years.
Stock Options. In the Current Period and the Prior Period, we granted members of management stock options that vest ratably over a three-year period. Each stock option award has an exercise price equal to the closing price of our common stock on the grant date. Outstanding options expire seven years to ten years from the date of grant.
We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method. Volatility assumptions are estimated based on the average historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account our dividend policy, over the expected life of the option. We used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Period:
Expected option life – years
 
6.0

Volatility
 
63.55
%
Risk-free interest rate
 
2.72
%
Dividend yield
 
—
%

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

The following table provides information related to stock option activity in the Current Period: 
 
 
Number of
Shares
Underlying  
Options
 
Weighted
Average
Exercise Price Per Share
 
Weighted  
Average
Contract Life in Years
 
Aggregate  
Intrinsic
Value(a)
 
 
(in thousands)
 
 
 
 
 
($ in millions)
Outstanding as of January 1, 2018
 
16,285

 
$
8.25

 
7.73
 
$
1

Granted
 
3,611

 
$
3.01

 
 
 
 
Exercised
 
—

 
$
—

 
 
 
$
—

Expired
 
(602
)
 
$
13.83

 
 
 
 
Forfeited
 
(1,067
)
 
$
5.45

 
 
 
 
Outstanding as of September 30, 2018
 
18,227

 
$
7.19

 
7.44
 
$
8

Exercisable as of September 30, 2018
 
8,250

 
$
10.73

 
6.05
 
$
2

___________________________________________
(a)
The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.
As of September 30, 2018, there was $16 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 1.74 years.
Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
($ in millions)
General and administrative expenses
 
$
6

 
$
9

 
$
21

 
$
20

Oil and natural gas properties
 
1

 
3

 
5

 
7

Oil, natural gas and NGL production expenses
 
1

 
2

 
4

 
7

Total restricted stock and stock option compensation
 
$
8

 
$
14

 
$
30

 
$
34

Liability-Classified Awards
Performance Share Units. We granted PSUs to senior management that vest ratably over a three-year performance period and are settled in cash. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors. Compensation expense associated with PSU awards is recognized over the service period based on the graded-vesting method. The value of the PSU awards at the end of each reporting period is dependent upon our estimates of the underlying performance measures.
For PSUs granted in 2017 and 2016, performance metrics include a total shareholder return (TSR) component, which can range from 0% to 100% and an operational performance component based on finding and development costs, which can range from 0% to 100%, resulting in a maximum payout of 200%. The payout percentage for the 2016 and 2017 PSU awards is capped at 100% if our absolute TSR is less than zero. The PSUs are settled in cash on the third anniversary of the awards. We utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the 2017 and 2016 PSU awards.
Grant Date Assumptions
Assumption
 
2017 Awards
 
2016 Awards
Volatility
 
80.65
%
 
49.74
%
Risk-free interest rate
 
1.54
%
 
1.13
%
Dividend yield for value of awards
 
—
%
 
—
%

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

Reporting Period Assumptions
Assumption
 
2017 Awards
 
2016 Awards
Volatility
 
51.65
%
 
41.46
%
Risk-free interest rate
 
2.65
%
 
2.19
%
Dividend yield for value of awards
 
—
%
 
—
%
As the above assumptions change, the PSU liabilities will be adjusted quarterly through the end of the performance period.
For PSUs granted in 2018, performance metrics include an operational performance component based on a ratio of cumulative earnings before interest expense, income taxes, and depreciation, depletion and amortization expense (EBITDA) to capital expenditures, for which payout can range from 0% to 200%. The vested PSUs are settled in cash on each of the three annual vesting dates. We used the closing price of our common stock on the grant date to determine the grant date fair value of the PSUs. The PSU liability will be adjusted quarterly, based on changes in our stock price and expected satisfaction of performance metrics, through the end of the performance period.
Cash Restricted Stock Units. In the Current Period, we granted CRSUs to employees that vest straight-line over a three-year period and are settled in cash on each of the three annual vesting dates. The ultimate amount earned is based on the closing price of our common stock on each of the vesting dates. We used the closing price of our common stock on the grant date to determine the grant date fair value of the CRSUs. The CRSU liability will be adjusted quarterly, based on changes in our stock price, through the end of the performance period. The CRSUs are subsequently adjusted, based on changes in our stock price through the end of each subsequent reporting period, through the end of each vesting period.
The following table presents a summary of our liability-classified awards:
 
 
 
 
Grant Date
Fair Value
 
September 30, 2018
 
 
Units
 
 
Fair Value
 
Vested Liability
 
 
 
 
($ in millions)
 
($ in millions)
2018 PSU Awards:
 
 
 
 
 
 
 
 
Payable 2019, 2020 and 2021
 
3,992,358

 
$
12

 
$
18

 
$
—

2017 PSU Awards:
 
 
 
 
 
 
 
 
Payable 2020
 
1,217,774

 
$
8

 
$
6

 
$
4

2016 PSU Awards:
 
 
 
 
 
 
 
 
Payable 2019
 
2,348,893

 
$
10

 
$
11

 
$
10

2018 CRSU Awards:
 
 
 
 
 
 
 
 
Payable 2019, 2020 and 2021
 
16,034,295

 
$
48

 
$
72

 
$
—


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

8.
Derivative and Hedging Activities
We use derivative instruments to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility. All of our oil, natural gas and NGL derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty. None of our open oil, natural gas and NGL derivative instruments were designated for hedge accounting as of September 30, 2018 or December 31, 2017.
Oil, Natural Gas and NGL Derivatives
As of September 30, 2018 and December 31, 2017, our oil, natural gas and NGL derivative instruments consisted of the following types of instruments:
•
Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options and call swaptions.
•
Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
•
Call Swaptions: We sell call swaptions to counterparties that allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time.
•
Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.
•
Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

The estimated fair values of our oil, natural gas and NGL derivative instrument assets (liabilities) as of September 30, 2018 and December 31, 2017 are provided below: 
 
 
September 30, 2018
 
December 31, 2017
 
 
Notional Volume
 
Fair Value
 
Notional Volume
 
Fair Value
 
 
 
 
($ in millions)  
 
 
 
($ in millions)  
Oil (mmbbl):
 
 
 
 
 
 
 
 
Fixed-price swaps
 
21

 
$
(294
)
 
21

 
$
(151
)
Three-way collars
 
—

 
(8
)
 
2

 
(10
)
Call swaptions
 
—

 
—

 
2

 
(13
)
Basis protection swaps
 
8

 
2

 
11

 
(9
)
Total oil
 
29

 
(300
)
 
36

 
(183
)
Natural gas (bcf):
 
 
 
 
 
 
 
 
Fixed-price swaps
 
400

(a) 
(19
)
 
532

 
149

Three-way collars
 
88

 
3

 
—

 
—

Collars
 
66

 
—

 
47

 
11

Call options
 
60

 
—

 
110

 
(3
)
Basis protection swaps
 
44

 
(7
)
 
65

 
(7
)
Total natural gas
 
658

 
(23
)
 
754

 
150

NGL (mmgal):
 
 
 
 
 
 
 
 
Fixed-price swaps
 
57

 
(15
)
 
33

 
(2
)
Total estimated fair value
 
 
 
$
(338
)
 
 
 
$
(35
)
____________________________________________
a)
Includes 170 bcf related to trades executed in accordance with the purchase and sale agreement with Encino.  These trades are reflected at fair market value as of September 30, 2018, with an offsetting receivable balance. The trades were novated to Encino upon closing of the purchase and sale agreement on October 29, 2018.
We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the original contract months are yet to occur. See further discussion below under Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss).


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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

Effect of Derivative Instruments – Condensed Consolidated Balance Sheets
The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of September 30, 2018 and December 31, 2017 on a gross basis and after same-counterparty netting:
Balance Sheet Classification
 
Gross
Fair Value
 
Amounts Netted
in the
Consolidated
Balance Sheets
 
Net Fair Value
Presented in the
Consolidated
Balance Sheet
 
 
($ in millions)
As of September 30, 2018
 
 
 
 
 
 
Commodity Contracts:
 
 
 
 
 
 
Short-term derivative asset
 
$
14

 
$
(14
)
 
$
—

Long-term derivative asset
 
3

 
(3
)
 
—

Short-term derivative liability
 
(324
)
 
14

 
(310
)
Long-term derivative liability
 
(31
)
 
3

 
(28
)
Total derivatives
 
$
(338
)
 
$
—

 
$
(338
)
 
 
 
 
 
 
 
As of December 31, 2017
 
 
 
 
 
 
Commodity Contracts:
 
 
 
 
 
 
Short-term derivative asset
 
$
157

 
$
(130
)
 
$
27

Short-term derivative liability
 
(188
)
 
130

 
(58
)
Long-term derivative liability
 
(4
)
 
—

 
(4
)
Total derivatives
 
$
(35
)
 
$
—

 
$
(35
)

Effect of Derivative Instruments – Condensed Consolidated Statements of Operations
The components of oil, natural gas and NGL revenues for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below:
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
($ in millions)
Oil, natural gas and NGL revenues
 
$
1,331

 
$
1,049

 
$
3,924

 
$
3,275

Gains (losses) on undesignated oil, natural gas
and NGL derivatives
 
(124
)
 
(62
)
 
(475
)
 
477

Losses on terminated cash flow hedges
 
(8
)
 
(8
)
 
(25
)
 
(25
)
Total oil, natural gas and NGL revenues
 
$
1,199

 
$
979

 
$
3,424

 
$
3,727



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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss)
A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below:
 
 
Three Months Ended September 30,
 
 
2018
 
2017
 
 
Before 
Tax  
 
After 
Tax  
 
Before 
Tax  
 
After 
Tax  
 
 
($ in millions)
Balance, beginning of period
 
$
(97
)
 
$
(40
)
 
$
(132
)
 
(75
)
Losses reclassified to income
 
8

 
8

 
8

 
8

Balance, end of period
 
$
(89
)
 
$
(32
)
 
(124
)
 
(67
)
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
2018
 
2017
 
 
Before 
Tax  
 
After 
Tax  
 
Before 
Tax  
 
After 
Tax  
 
 
($ in millions)
Balance, beginning of period
 
$
(114
)
 
$
(57
)
 
$
(153
)
 
$
(96
)
Net change in fair value
 
—

 
—

 
4

 
4

Losses reclassified to income
 
25

 
25

 
25

 
25

Balance, end of period
 
$
(89
)
 
$
(32
)
 
$
(124
)
 
$
(67
)
The accumulated other comprehensive loss as of September 30, 2018 represents the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the original contract months are yet to occur. Remaining deferred gain or loss amounts will be recognized in earnings in the month for which the original contract months are to occur. As of September 30, 2018, we expect to transfer approximately $35 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. The remaining amounts will be transferred by December 31, 2022.
Credit Risk Considerations
Our derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are highly rated or deemed by us to have acceptable credit strength and deemed by management to be competent and competitive market-makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of September 30, 2018, our oil, natural gas and NGL derivative instruments were spread among 11 counterparties.
Hedging Arrangements
Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under our revolving credit facility. The contracts entered into with these counterparties are secured by the same collateral that secures our revolving credit facility. In addition, we enter into bilateral hedging agreements with other counterparties. The counterparties’ and our obligations under the bilateral hedging agreements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds. As of September 30, 2018, we posted $14 million in letters of credit as collateral for our commodity derivatives. No cash was posted as collateral for our commodity derivatives.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

Fair Value
The fair value of our derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil, natural gas and NGL forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are compared to the values given by our counterparties for reasonableness. Since oil, natural gas and NGL swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives.
The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017: 
 
 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2) 
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
Fair Value
 
 
 
 
($ in millions)
 
 
As of September 30, 2018
 
 
 
 
 
 
 
 
Derivative Assets (Liabilities):
 
 
 
 
 
 
 
 
Commodity assets
 
$
—

 
$
7

 
$
11

 
$
18

Commodity liabilities
 
—

 
(340
)
 
(16
)
 
(356
)
Total derivatives
 
$
—

 
$
(333
)
 
$
(5
)
 
$
(338
)
 
 
 
 
 
 
 
 
 
As of December 31, 2017
 
 
 
 
 
 
 
 
Derivative Assets (Liabilities):
 
 
 
 
 
 
 
 
Commodity assets
 
$
—

 
$
—

 
$
8

 
$
8

Commodity liabilities
 
—

 
(20
)
 
(23
)
 
(43
)
Total derivatives
 
$
—

 
$
(20
)
 
$
(15
)
 
$
(35
)


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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during the Current Period and the Prior Period is presented below: 
 
 
Commodity
Derivatives
 
 
($ in millions)
Balance, as of January 1, 2018
 
$
(15
)
Total gains (losses) (realized/unrealized):
 
 
Included in earnings(a)
 
(3
)
Total purchases, issuances, sales and settlements:
 
 
Settlements
 
13

Balance, as of September 30, 2018
 
$
(5
)
 
 
 
Balance, as of January 1, 2017
 
$
(10
)
Total gains (losses) (realized/unrealized):
 
 
Included in earnings(a)
 
1

Total purchases, issuances, sales and settlements:
 
 
Settlements
 
1

Balance, as of September 30, 2017
 
$
(8
)
___________________________________________
(a)
 
 
Commodity Derivatives
 
 
 
 
 
2018
 
2017
 
 
 
($ in millions)
 
Total gains (losses) included in earnings for the period
 
$
(3
)
 
$
1

 
Change in unrealized gains (losses) related to assets
still held at reporting date
 
$
(3
)
 
$
(7
)
Qualitative and Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements
The significant unobservable inputs for Level 3 derivative contracts include market volatility. Changes in market volatility impacts the fair value measurement of our derivative contracts, which is based on an estimate derived from option models. For example, an increase or decrease in the forward prices and volatility of oil and natural gas prices decreases or increases the fair value of oil and natural gas derivatives. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of September 30, 2018:
Instrument
Type
 
Unobservable
Input
 
Range
 
Weighted
Average
 
Fair Value
September 30, 2018
 
 
 
 
 
 
 
 
($ in millions)
Oil trades
 
Oil price volatility curves
 
19.09% – 28.60%
 
24.97%
 
$
(8
)
Natural gas trades
 
Natural gas price volatility curves
 
15.60% – 62.08%
 
16.24%
 
$
3



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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

9.
Oil and Natural Gas Property Transactions
Under full cost accounting rules, we account for sales of oil and natural gas properties as adjustments to capitalized costs, with no recognition of gain or loss unless a sale involves a significant change in proved reserves and significantly alters the relationship between capitalized costs and proved reserves.
On October 29, 2018 we sold all of our approximately 1,500,000 gross (900,000 net) acres in Ohio, of which approximately 320,000 net acres are prospective for the Utica Shale with approximately 920 producing wells, along with related property and equipment (collectively, the “Designated Properties”) for net proceeds of $1.868 billion to Encino, with additional contingent payments to us of up to $100 million comprised of $50 million in consideration in each case if, on or prior to December 31, 2019, there is a period of twenty (20) trading days out of a period of thirty (30) consecutive trading days where (i) the average of the NYMEX natural gas strip prices for the months comprising the year 2022 equals or exceeds $3.00/mmbtu as calculated pursuant to the purchase agreement, and (ii) the average of the NYMEX natural gas price strip prices for the months comprising the year 2023 equals or exceeds $3.25/mmbtu as calculated pursuant to the purchase agreement.
We expect the sale of our Designated Properties to Encino to involve a significant change in proved reserves and to significantly alter the relationship between costs and proved reserves and therefore to result in the recognition of loss upon closing of that transaction. Under SEC rules for full cost companies, a transaction is deemed to be significant if the properties being sold represent 25% or more of the reserve quantities of the divesting company.
In the Current Period, we sold portions of our acreage, producing properties and other related property and equipment in the Mid-Continent, including our Mississippian Lime assets, for approximately $491 million, subject to certain customary closing adjustments. Included in the sales were approximately 238,500 net acres and interests in approximately 3,200 wells. Also, in the Current Quarter and the Current Period, we received proceeds of approximately $8 million and $31 million, respectively, subject to customary closing adjustments, for the sale of other oil and natural gas properties covering various operating areas.
In the Prior Period, we sold portions of our acreage and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $915 million, subject to certain customary closing adjustments. Included in the sales were approximately 119,500 net acres and interests in 576 wells that were producing approximately 80 mmcf of gas per day at the time of closing. Also in the Prior Quarter and the Prior Period, we received proceeds of approximately $248 million and $331 million, respectively, net of post-closing adjustments, for the sale of other oil and natural gas properties covering various operating areas.
Volumetric Production Payments
A VPP is a limited-term overriding royalty interest in oil and natural gas reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is non-recourse to the seller (i.e., the purchaser’s only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain all production beyond the specified volumes, if any, after the scheduled production volumes have been delivered. If contractually scheduled volumes exceed the actual volumes produced from the VPP wellbores that are attributable to the ORRI conveyed, either the shortfall will be made up from future production from these wellbores (or, at our option, from our retained interest in the wellbores) through an adjustment mechanism, or the initial term of the VPP will be extended until all scheduled volumes, to the extent produced, are delivered from the VPP wellbores to the VPP buyer. We retain drilling rights on the properties below currently producing intervals and outside of producing wellbores.
As the operator of the properties from which the VPP volumes have been sold, we bear the cost of producing the reserves attributable to these interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods these costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining our full cost ceiling test for impairment purposes and in determining our standardized measure. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. Future costs will depend on the actual production volumes as well as the production costs and taxes in effect during the periods in which the production actually occurs, which could differ materially from our current and historical costs, and production may not occur at the times or in the quantities projected, or at all.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

We have committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.
As of September 30, 2018, we had the following VPP outstanding:
 
 
 
 
 
 
 
 
Volume Sold
VPP #
 
Date of VPP        
 
Location
 
Proceeds
 
Oil
 
Natural Gas
 
NGL
 
Total
 
 
 
 
 
 
($ in millions)
 
(mmbbl)
 
 (bcf)
 
(mmbbl)
 
(bcfe)
9
 
May 2011
 
Mid-Continent
 
$
853

 
1.7

 
138

 
4.8

 
177

The volumes remaining to be delivered on behalf of our VPP buyers as of September 30, 2018 were as follows:
 
 
 
 
Volume Remaining as of September 30, 2018
VPP #
 
Term Remaining
 
Oil
 
Natural Gas
 
NGL
 
Total
 
 
(in months)
 
 (mmbbl)
 
 (bcf)
 
 (mmbbl)
 
 (bcfe)
9
 
29
 
0.3

 
25.8

 
0.7

 
31.4


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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

10.
Revenue Recognition
The FASB issued Revenue from Contracts with Customers (Topic 606) superseding virtually all existing revenue recognition guidance. We adopted this new standard in the first quarter of 2018 using the modified retrospective approach. We applied the new standard to all contracts that were not completed as of January 1, 2018 and reflected the aggregate effect of all modifications in determining and allocating the transaction price. The cumulative effect of adoption of $8 million did not have a material impact on our condensed consolidated financial statements. However, the adoption did result in certain purchase and sale contracts being recorded on a net basis, as an agent, rather than on a gross basis, as principal, due to management’s evaluation under new considerations within Topic 606 that indicated we do not have control over the specified commodity in purchase and sale contracts with the same counterparty. Such presentation change did not have an impact on income (loss) from operations, earnings per share or cash flows.
In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our condensed consolidated statements of operations was as follows:
 
 
Before adoption of ASC 606
 
Adjustments
 
As Reported
 
 
 
 
($ in millions)
 
 
Statement of Operations for the Three Months Ended September 30, 2018
 
 
 
Marketing revenues
 
$
1,508

 
$
(289
)
 
$
1,219

Marketing operating expenses
 
$
1,516

 
$
(278
)
 
$
1,238

 
 
 
 
 
 
 
Statement of Operations for the Nine Months Ended September 30, 2018
 
 
 
 
Marketing revenues
 
$
4,320

 
$
(582
)
 
$
3,738

Marketing operating expenses
 
$
4,365

 
$
(567
)
 
$
3,798

Revenue from the sale of oil, natural gas and NGL is recognized upon the transfer of control of the products, which is typically when the products are delivered to customers. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products.
Revenue from contracts with customers includes the sale of our oil, natural gas and NGL production (recorded as oil, natural gas and NGL revenues in the condensed consolidated statements of operations) as well as the sale of certain of our joint interest holders’ production which we purchase under joint operating arrangements (recorded in marketing revenues in the condensed consolidated statements of operations). In connection with the marketing of these products, we obtain control of the oil, natural gas and NGL we purchase from other interest owners at defined delivery points and deliver the product to third parties, at which time revenues are recorded.
Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 days. There are no significant judgments that significantly affect the amount or timing of revenue from contracts with customers. 
We also earn revenue from other sources, including from a variety of derivative and hedging activities to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility, (recorded within oil, natural gas and NGL revenues in the condensed consolidated statements of operations) as well as a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and satisfaction of our pipeline delivery commitments (recorded within marketing revenues in the condensed consolidated statements of operations).
In circumstances where we act as an agent rather than a principal, our results of operations related to oil, natural gas and NGL marketing activities are presented on a net basis. These purchase and sales contracts were accounted for as derivatives under Derivatives and Hedging (Topic 815) and were not elected as normal purchase or normal sales. We considered the principal versus agent guidance in Topic 606 in determining whether the gains and losses on these derivatives should be reported on a gross or net basis.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

The following table shows revenue disaggregated by operating area and product type, for the Current Quarter and the Current Period:
 
 
Three Months Ended September 30, 2018
 
 
Oil
 
Natural Gas
 
NGL
 
Total
 
 
($ in millions)
Marcellus
 
$
—

 
$
184

 
$
—

 
$
184

Haynesville
 
—

 
195

 
—

 
195

Eagle Ford
 
399

 
36

 
58

 
493

Utica
 
59

 
131

 
76

 
266

Mid-Continent
 
58

 
15

 
12

 
85

Powder River Basin
 
78

 
17

 
13

 
108

Revenue from contracts with customers
 
594

 
578

 
159

 
1,331

Losses on oil, natural gas and NGL derivatives
 
(100
)
 
(18
)
 
(14
)
 
(132
)
Oil, natural gas and NGL revenue
 
$
494

 
$
560

 
$
145

 
$
1,199

 
 
 
 
 
 
 
 
 
Marketing revenue from contracts with customers
 
$
707

 
$
211

 
$
112

 
$
1,030

Other marketing revenue
 
119

 
70

 
—

 
189

Marketing revenue
 
$
826

 
$
281

 
$
112

 
$
1,219

 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
 
Oil
 
Natural Gas
 
NGL
 
Total
 
 
($ in millions)
Marcellus
 
$
—

 
$
646

 
$
—

 
$
646

Haynesville
 
2

 
603

 
—

 
605

Eagle Ford
 
1,148

 
120

 
143

 
1,411

Utica
 
179

 
350

 
189

 
718

Mid-Continent
 
196

 
63

 
42

 
301

Powder River Basin
 
173

 
40

 
30

 
243

Revenue from contracts with customers
 
1,698

 
1,822

 
404

 
3,924

Losses on oil, natural gas and NGL derivatives
 
(388
)
 
(85
)
 
(27
)
 
(500
)
Oil, natural gas and NGL revenue
 
$
1,310

 
$
1,737

 
$
377

 
$
3,424

 
 
 
 
 
 
 
 
 
Marketing revenue from contracts with customers
 
$
2,125

 
$
733

 
$
324

 
$
3,182

Other marketing revenue
 
381

 
175

 
—

 
556

Marketing revenue
 
$
2,506

 
$
908

 
$
324

 
$
3,738


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

Accounts Receivable
Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties deemed to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables that we believe may be uncollectible. Accounts receivable as of September 30, 2018 and December 31, 2017 are detailed below:
 
 
September 30, 2018
 
December 31,
2017
 
 
($ in millions)
Oil, natural gas and NGL sales
 
$
829

 
$
959

Joint interest
 
160

 
209

Other
 
78

 
184

Allowance for doubtful accounts
 
(16
)
 
(30
)
Total accounts receivable, net
 
$
1,051

 
$
1,322

11.
Investments
In the Current Period, FTS International, Inc. (NYSE: FTSI) completed an initial public offering. Due to the offering, the ownership percentage of our equity method investment in FTSI decreased from approximately 29% to 24% and resulted in a gain of $78 million. In addition, we sold approximately 4.3 million shares of FTSI in the offering for net proceeds of approximately $74 million and recognized a gain of $61 million decreasing our ownership percentage to approximately 20%. We continue to hold approximately 22.0 million shares in the publicly traded company.
12.
Impairments
In the Current Period, we have determined that certain of our other fixed assets will either be sold or disposed before the end of their useful lives indicating the carrying value may not be recoverable. As a result, we recognized an impairment loss of $51 million in the Current Period for the difference between the carrying amount and fair value of the assets.
13.
Other Operating Expenses
In the Prior Period, we terminated future natural gas transportation commitments related to divested assets for cash payments of $126 million. In the Prior Period, we paid $290 million to assign an oil transportation agreement to a third party.
14.
Restructuring and Other Termination Costs
Workforce Reduction
On January 30, 2018, we underwent a reduction in workforce impacting approximately 13% of employees across all functions, primarily on our Oklahoma City campus. In connection with the reduction, we incurred a total charge in the Current Period of approximately $38 million for one-time termination benefits. The following table summarizes our restructuring liabilities:
 
 
Other Current Liabilities
 
 
($ in millions)
Balance as of December 31, 2017
 
$
—

Initial restructuring recognition on January 30, 2018
 
38

Termination benefits paid
 
(38
)
Balance as of September 30, 2018
 
$
—


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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

15.
Fair Value Measurements
Recurring Fair Value Measurements
Other Current Assets. Assets related to our deferred compensation plan are included in other current assets. The fair value of these assets is determined using quoted market prices, as they consist of exchange-traded securities.
Other Current Liabilities. Liabilities related to our deferred compensation plan are included in other current liabilities. The fair values of these liabilities are determined using quoted market prices, as the plan consists of exchange-traded mutual funds.
Financial Assets (Liabilities). The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017:
 
 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2) 
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
Fair Value
 
 
($ in millions)
As of September 30, 2018
 
 
 
 
 
 
 
 
Financial Assets (Liabilities):
 
 
 
 
 
 
 
 
Other current assets
 
$
54

 
$
—

 
$
—

 
$
54

Other current liabilities
 
(54
)
 
—

 
—

 
(54
)
Total
 
$
—

 
$
—

 
$
—

 
$
—

 
 
 
 
 
 
 
 
 
As of December 31, 2017
 
 
 
 
 
 
 
 
Financial Assets (Liabilities):
 
 
 
 
 
 
 
 
Other current assets
 
$
57

 
$
—

 
$
—

 
$
57

Other current liabilities
 
(60
)
 
—

 
—

 
(60
)
Total
 
$
(3
)
 
$
—

 
$
—

 
$
(3
)
See Note 3 for information regarding fair value measurement of our debt instruments. See Note 8 for information regarding fair value measurement of our derivatives.

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TABLE OF CONTENTS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

16.
Condensed Consolidating Financial Information
Chesapeake Energy Corporation is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes, contingent convertible senior notes and revolving credit facility listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries. Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries are non-guarantors.
The tables below are condensed consolidating financial statements for Chesapeake Energy Corporation (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of September 30, 2018 and December 31, 2017 and for the three and nine months ended September 30, 2018 and 2017. This financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities.

32
TABLE OF CONTENTS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET
AS OF SEPTEMBER 30, 2018
($ in millions) 
 
 
Parent  
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
CURRENT ASSETS:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
6

 
$
1

 
$
1

 
$
(4
)
 
$
4

Other current assets
 
69

 
1,160

 
2

 
—

 
1,231

Intercompany receivable, net
 
8,003

 
29

 
176

 
(8,208
)
 
—

Total Current Assets
 
8,078

 
1,190

 
179

 
(8,212
)
 
1,235

PROPERTY AND EQUIPMENT:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas properties at cost,
based on full cost accounting, net
 
563

 
9,433

 
25

 
—

 
10,021

Other property and equipment, net
 
—

 
1,109

 
—

 
—

 
1,109

Property and equipment
held for sale, net
 
—

 
47

 
—

 
—

 
47

Total Property and Equipment,
Net
 
563

 
10,589

 
25

 
—

 
11,177

LONG-TERM ASSETS:
 
 
 
 
 
 
 
 
 
 
Other long-term assets
 
29

 
218

 
—

 
—

 
247

Investments in subsidiaries and
intercompany advances
 
1,193

 
79

 
—

 
(1,272
)
 
—

TOTAL ASSETS
 
$
9,863

 
$
12,076

 
$
204

 
$
(9,484
)
 
$
12,659

 
 
 
 
 
 
 
 
 
 
 
CURRENT LIABILITIES:
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
$
563

 
$
2,415

 
$
2

 
$
(4
)
 
$
2,976

Intercompany payable, net
 
29

 
8,179

 
—

 
(8,208
)
 
—

Total Current Liabilities
 
592

 
10,594

 
2

 
(8,212
)
 
2,976

LONG-TERM LIABILITIES:
 
 
 
 
 
 
 
 
 
 
Long-term debt, net
 
9,380

 
—

 
—

 
—

 
9,380

Other long-term liabilities
 
53

 
289

 
—

 
—

 
342

Total Long-Term Liabilities
 
9,433

 
289

 
—

 
—

 
9,722

EQUITY:
 
 
 
 
 
 
 
 
 
 
Chesapeake stockholders’ equity (deficit)
 
(162
)
 
1,193

 
79

 
(1,272
)
 
(162
)
Noncontrolling interests
 
—

 
—

 
123

 
—

 
123

Total Equity (Deficit)
 
(162
)
 
1,193

 
202

 
(1,272
)
 
(39
)
TOTAL LIABILITIES AND EQUITY
 
$
9,863

 
$
12,076

 
$
204

 
$
(9,484
)
 
$
12,659


33
TABLE OF CONTENTS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2017
($ in millions)
 
 
Parent  
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
CURRENT ASSETS:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
5

 
$
1

 
$
2

 
$
(3
)
 
$
5

Other current assets
 
154

 
1,364

 
3

 
(1
)
 
1,520

Intercompany receivable, net
 
8,697

 
436

 
—

 
(9,133
)
 
—

Total Current Assets
 
8,856

 
1,801

 
5

 
(9,137
)
 
1,525

PROPERTY AND EQUIPMENT:
 
 
 
 
 
 
 
 
 
 
Oil and natural gas properties at cost,
based on full cost accounting, net
 
435

 
8,888

 
27

 
—

 
9,350

Other property and equipment, net
 
—

 
1,314

 
—

 
—

 
1,314

Property and equipment
held for sale, net
 
—

 
16

 
—

 
—

 
16

Total Property and Equipment,
Net
 
435

 
10,218

 
27

 
—

 
10,680

LONG-TERM ASSETS:
 
 
 
 
 
 
 
 
 
 
Other long-term assets
 
52

 
168

 
—

 
—

 
220

Investments in subsidiaries and
intercompany advances
 
806

 
(146
)
 
—

 
(660
)
 
—

TOTAL ASSETS
 
$
10,149

 
$
12,041

 
$
32

 
$
(9,797
)
 
$
12,425

 
 
 
 
 
 
 
 
 
 
 
CURRENT LIABILITIES:
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
$
190

 
$
2,168

 
$
2

 
$
(4
)
 
$
2,356

Intercompany payable, net
 
433

 
8,648

 
52

 
(9,133
)
 
—

Total Current Liabilities
 
623

 
10,816

 
54

 
(9,137
)
 
2,356

LONG-TERM LIABILITIES:
 
 
 
 
 
 
 
 
 
 
Long-term debt, net
 
9,921

 
—

 
—

 
—

 
9,921

Other long-term liabilities
 
101

 
419

 
—

 
—

 
520

Total Long-Term Liabilities
 
10,022

 
419

 
—

 
—

 
10,441

EQUITY:
 
 
 
 
 
 
 
 
 
 
Chesapeake stockholders’ equity (deficit)
 
(496
)
 
806

 
(146
)
 
(660
)
 
(496
)
Noncontrolling interests
 
—

 
—

 
124

 
—

 
124

Total Equity (Deficit)
 
(496
)
 
806

 
(22
)
 
(660
)
 
(372
)
TOTAL LIABILITIES AND EQUITY
 
$
10,149

 
$
12,041

 
$
32

 
$
(9,797
)
 
$
12,425



34
TABLE OF CONTENTS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2018
($ in millions)
 
 
Parent  
 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
REVENUES:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and NGL
 
$
—

 
$
1,194

 
$
5

 
$
—

 
$
1,199

Marketing
 
—

 
1,219

 
—

 
—

 
1,219

Total Revenues
 
—

 
2,413

 
5

 
—

 
2,418

OPERATING EXPENSES:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and NGL production
 
—

 
132

 
—

 
—

 
132

Oil, natural gas and NGL gathering, processing and transportation
 
—

 
362

 
2

 
—

 
364

Production taxes
 
—

 
33

 
1

 
—

 
34

Marketing
 
—

 
1,238

 
—

 
—

 
1,238

General and administrative
 
—

 
66

 
—

 
—

 
66

Provision for legal contingencies, net
 
—

 
8

 
—

 
—

 
8

Oil, natural gas and NGL depreciation,
depletion and amortization
 
—

 
274

 
—

 
—

 
274

Depreciation and amortization of other
assets
 
—

 
17

 
—

 
—

 
17

Impairments
 
—

 
5

 
—

 
—

 
5

Total Operating Expenses
 
—

 
2,135

 
3

 
—

 
2,138

INCOME FROM OPERATIONS
 
—

 
278

 
2

 
—

 
280

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
 
 
 
Interest expense
 
(125
)
 
(2
)
 
—

 
—

 
(127
)
Losses on purchases or exchanges of debt
 
(68
)
 
—

 
—

 
—

 
(68
)
Other income
 
—

 
1

 
—

 
—

 
1

Equity in net earnings of subsidiary
 
278

 
1

 
—

 
(279
)
 
—

Total Other Income (Expense)
 
85

 
—

 
—

 
(279
)
 
(194
)
INCOME BEFORE INCOME TAXES
 
85

 
278

 
2

 
(279
)
 
86

INCOME TAX EXPENSE
 
1

 
—

 
—

 
—

 
1

NET INCOME
 
84

 
278

 
2

 
(279
)
 
85

Net income attributable to
noncontrolling interests
 
—

 
—

 
(1
)
 
—

 
(1
)
NET INCOME ATTRIBUTABLE
TO CHESAPEAKE
 
84

 
278

 
1

 
(279
)
 
84

Other comprehensive income
 
—

 
8

 
—

 
—

 
8

COMPREHENSIVE INCOME
ATTRIBUTABLE TO CHESAPEAKE
 
$
84

 
$
286

 
$
1

 
$
(279
)
 
$
92



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TABLE OF CONTENTS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2017
($ in millions)
 
 
Parent  
 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
REVENUES:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and NGL
 
$
—

 
$
974

 
$
5

 
$
—

 
$
979

Marketing
 
—

 
964

 
—

 
—

 
964

Total Revenues
 
—

 
1,938

 
5

 
—

 
1,943

OPERATING EXPENSES:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and NGL production
 
—

 
151

 
—

 
—

 
151

Oil, natural gas and NGL gathering, processing and transportation
 
—

 
367

 
2

 
—

 
369

Production taxes
 
—

 
20

 
1

 
—

 
21

Marketing
 
—

 
978

 
—

 
—

 
978

General and administrative
 
—

 
54

 
—

 
—

 
54

Provision for legal contingencies, net
 
—

 
20

 
—

 
—

 
20

Oil, natural gas and NGL depreciation,
depletion and amortization
 
—

 
227

 
1

 
—

 
228

Depreciation and amortization of other
assets
 
—

 
20

 
—

 
—

 
20

Impairments
 
—

 
3

 
—

 
—

 
3

Net gains on sales of fixed assets
 
—

 
(1
)
 
—

 
—

 
(1
)
Other operating expense
 
—

 
6

 
—

 
—

 
6

Total Operating Expenses
 
—

 
1,845

 
4

 
—

 
1,849

INCOME FROM OPERATIONS
 
—

 
93

 
1

 
—

 
94

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
 
 
 
Interest expense
 
(110
)
 
(4
)
 
—

 
—

 
(114
)
Losses on purchases or exchanges of debt
 
(1
)
 
—

 
—

 
—

 
(1
)
Other income
 
1

 
3

 
—

 
—

 
4

Equity in net earnings of subsidiary
 
92

 
—

 
—

 
(92
)
 
—

Total Other Income (Expense)
 
(18
)
 
(1
)
 
—

 
(92
)
 
(111
)
INCOME (LOSS) BEFORE INCOME TAXES
 
(18
)
 
92

 
1

 
(92
)
 
(17
)
INCOME TAX EXPENSE
 
—

 
—

 
—

 
—

 
—

NET INCOME (LOSS)
 
(18
)
 
92

 
1

 
(92
)
 
(17
)
Net income attributable to
noncontrolling interests
 
—

 
—

 
(1
)
 
—

 
(1
)
NET INCOME (LOSS) ATTRIBUTABLE
TO CHESAPEAKE
 
(18
)
 
92

 
—

 
(92
)
 
(18
)
Other comprehensive income
 
—

 
8

 
—

 
—

 
8

COMPREHENSIVE INCOME (LOSS)
ATTRIBUTABLE TO CHESAPEAKE
 
$
(18
)
 
$
100

 
$
—

 
$
(92
)
 
$
(10
)


36
TABLE OF CONTENTS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2018
($ in millions)
 
 
Parent  
 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
REVENUES:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and NGL
 
$
—

 
$
3,410

 
$
14

 
$
—

 
$
3,424

Marketing
 
—

 
3,738

 
—

 
—

 
3,738

Total Revenues
 
—

 
7,148

 
14

 
—

 
7,162

OPERATING EXPENSES:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and NGL production
 
—

 
417

 
—

 
—

 
417

Oil, natural gas and NGL gathering, processing and transportation
 
—

 
1,055

 
5

 
—

 
1,060

Production taxes
 
—

 
90

 
1

 
—

 
91

Marketing
 
—

 
3,798

 
—

 
—

 
3,798

General and administrative
 
—

 
228

 
1

 
—

 
229

Restructuring and other termination costs
 
—

 
38

 
—

 
—

 
38

Provision for legal contingencies, net
 
—

 
17

 
—

 
—

 
17

Oil, natural gas and NGL depreciation,
depletion and amortization
 
—

 
811

 
2

 
—

 
813

Depreciation and amortization of other assets
 
—

 
54

 
—

 
—

 
54

Impairments
 
—

 
51

 
—

 
—

 
51

Other operating income
 
—

 
(1
)
 
—

 
—

 
(1
)
Net losses on sales of fixed assets
 
—

 
7

 
—

 
—

 
7

Total Operating Expenses
 
—

 
6,565

 
9

 
—

 
6,574

INCOME FROM OPERATIONS
 
—

 
583

 
5

 
—

 
588

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
 
 
 
Interest expense
 
(365
)
 
(2
)
 
—

 
—

 
(367
)
Gains on investments
 
—

 
139

 
—

 
—

 
139

Losses on exchanges or repurchases of debt
 
(68
)
 
—

 
—

 
—

 
(68
)
Other income
 
—

 
63

 
—

 
—

 
63

Equity in net earnings of subsidiary
 
785

 
2

 
—

 
(787
)
 
—

Total Other Income (Expense)
 
352

 
202

 
—

 
(787
)
 
(233
)
INCOME BEFORE INCOME TAXES
 
352

 
785

 
5

 
(787
)
 
355

INCOME TAX BENEFIT
 
(8
)
 
—

 
—

 
—

 
(8
)
NET INCOME
 
360

 
785

 
5

 
(787
)
 
363

Net income attributable to
noncontrolling interests
 
—

 
—

 
(3
)
 
—

 
(3
)
NET INCOME ATTRIBUTABLE
TO CHESAPEAKE
 
360

 
785

 
2

 
(787
)
 
360

Other comprehensive income
 
—

 
25

 
—

 
—

 
25

COMPREHENSIVE INCOME
ATTRIBUTABLE TO CHESAPEAKE
 
$
360

 
$
810

 
$
2

 
$
(787
)
 
$
385




37
TABLE OF CONTENTS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2017
($ in millions)
 
 
Parent  
 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
REVENUES:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and NGL
 
$
—

 
$
3,710

 
$
17

 
$
—

 
$
3,727

Marketing
 
—

 
3,250

 
—

 
—

 
3,250

Total Revenues
 
—

 
6,960

 
17

 
—

 
6,977

OPERATING EXPENSES:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and NGL production
 
—

 
426

 
—

 
—

 
426

Oil, natural gas and NGL gathering, processing and transportation
 
—

 
1,075

 
6

 
—

 
1,081

Production taxes
 
—

 
63

 
1

 
—

 
64

Marketing
 
—

 
3,333

 
—

 
—

 
3,333

General and administrative
 
3

 
185

 
1

 
—

 
189

Provision for legal contingencies, net
 
—

 
35

 
—

 
—

 
35

Oil, natural gas and NGL depreciation,
depletion and amortization
 
—

 
624

 
3

 
—

 
627

Depreciation and amortization of other
assets
 
—

 
62

 
—

 
—

 
62

Impairments
 
—

 
3

 
—

 
—

 
3

Other operating expense
 
—

 
423

 
—

 
—

 
423

Total Operating Expenses
 
3

 
6,229

 
11

 
—

 
6,243

INCOME (LOSS) FROM OPERATIONS
 
(3
)
 
731

 
6

 
—

 
734

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
 
 
 
Interest expense
 
(300
)
 
(2
)
 
—

 
—

 
(302
)
Gains on purchases or exchanges of debt
 
183

 
—

 
—

 
—

 
183

Other income
 
1

 
5

 
—

 
—

 
6

Equity in net earnings of subsidiary
 
737

 
3

 
—

 
(740
)
 
—

Total Other Income (Expense)
 
621

 
6

 
—

 
(740
)
 
(113
)
INCOME BEFORE INCOME TAXES
 
618

 
737

 
6

 
(740
)
 
621

INCOME TAX EXPENSE
 
2

 
—

 
—

 
—

 
2

NET INCOME
 
616

 
737

 
6

 
(740
)
 
619

Net income attributable to
noncontrolling interests
 
—

 
—

 
(3
)
 
—

 
(3
)
NET INCOME ATTRIBUTABLE
TO CHESAPEAKE
 
616

 
737

 
3

 
(740
)
 
616

Other comprehensive income
 
—

 
29

 
—

 
—

 
29

COMPREHENSIVE INCOME
ATTRIBUTABLE TO CHESAPEAKE
 
$
616

 
$
766

 
$
3

 
$
(740
)
 
$
645


38
TABLE OF CONTENTS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2018
($ in millions) 
 
 
Parent  
 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
CASH FLOWS FROM
OPERATING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Net Cash Provided By
Operating Activities
 
$
86

 
$
1,512

 
$
7

 
$
(10
)
 
$
1,595

 
 
 
 
 
 
 
 
 
 
 
CASH FLOWS FROM
INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Drilling and completion costs
 
—

 
(1,481
)
 
—

 
—

 
(1,481
)
Acquisitions of proved and unproved properties
 
—

 
(244
)
 
—

 
—

 
(244
)
Proceeds from divestitures of proved and unproved properties
 
—

 
395

 
—

 
—

 
395

Additions to other property and equipment
 
—

 
(11
)
 
—

 
—

 
(11
)
Other investing activities
 
—

 
149

 
—

 
—

 
149

Net Cash Used In
Investing Activities
 
—

 
(1,192
)
 
—

 
—

 
(1,192
)
 
 
 
 
 
 
 
 
 
 
 
CASH FLOWS FROM
FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Proceeds from revolving credit facility borrowings
 
9,095

 
—

 
—

 
—

 
9,095

Payments on revolving credit facility borrowings
 
(9,231
)
 
—

 
—

 
—

 
(9,231
)
Proceeds from issuance of senior notes, net
 
1,237

 
—

 
—

 
—

 
1,237

Cash paid to purchase debt
 
(1,285
)
 
—

 
—

 
—

 
(1,285
)
Cash paid for preferred stock dividends
 
(69
)
 
—

 
—

 
—

 
(69
)
Other financing activities
 
(2
)
 
(127
)
 
(9
)
 
(13
)
 
(151
)
Intercompany advances, net
 
170

 
(193
)
 
1

 
22

 
—

Net Cash Used In
Financing Activities
 
(85
)
 
(320
)
 
(8
)
 
9

 
(404
)
Net increase (decrease) in cash and cash equivalents
 
1

 
—

 
(1
)
 
(1
)
 
(1
)
Cash and cash equivalents,
beginning of period
 
5

 
1

 
2

 
(3
)
 
5

Cash and cash equivalents, end of period
 
$
6

 
$
1

 
$
1

 
$
(4
)
 
$
4



39
TABLE OF CONTENTS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2017
($ in millions)
 
 
Parent  
 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
CASH FLOWS FROM
OPERATING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Net Cash Provided By
Operating Activities
 
$
4

 
$
266

 
$
11

 
$
(8
)
 
$
273

 
 
 
 
 
 
 
 
 
 
 
CASH FLOWS FROM
INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Drilling and completion costs
 
—

 
(1,597
)
 
—

 
—

 
(1,597
)
Acquisitions of proved and unproved properties
 
—

 
(226
)
 
—

 
—

 
(226
)
Proceeds from divestitures of proved and unproved properties
 
—

 
1,193

 
—

 
—

 
1,193

Additions to other property and equipment
 
—

 
(12
)
 
—

 
—

 
(12
)
Other investing activities
 
—

 
40

 
—

 
—

 
40

Net Cash Used In
Investing Activities
 
—

 
(602
)
 
—

 
—

 
(602
)
 
 
 
 
 
 
 
 
 
 
 
CASH FLOWS FROM
FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Proceeds from revolving credit facility borrowings
 
4,775

 
—

 
—

 
—

 
4,775

Payments on revolving credit facility borrowings
 
(4,130
)
 
—

 
—

 
—

 
(4,130
)
Proceeds from issuance of senior notes, net
 
742

 
—

 
—

 
—

 
742

Cash paid to purchase debt
 
(1,751
)
 
—

 
—

 
—

 
(1,751
)
Cash paid for preferred stock dividends
 
(160
)
 
—

 
—

 
—

 
(160
)
Other financing activities
 
(36
)
 
(4
)
 
(11
)
 
27

 
(24
)
Intercompany advances, net
 
(339
)
 
339

 
—

 
—

 
—

Net Cash Provided by (Used In)
Financing Activities
 
(899
)
 
335

 
(11
)
 
27

 
(548
)
Net increase (decrease) in cash and cash equivalents
 
(895
)
 
(1
)
 
—

 
19

 
(877
)
Cash and cash equivalents,
beginning of period
 
904

 
2

 
1

 
(25
)
 
882

Cash and cash equivalents, end of period
 
$
9

 
$
1

 
$
1

 
$
(6
)
 
$
5




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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

17.
Subsequent Events
On October 30, 2018, we jointly announced with WildHorse Resource Development Corporation (“WildHorse”) that we have entered into a definitive agreement to acquire WildHorse, an oil and gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas, in a transaction valued at approximately $3.977 billion, including the value of WildHorse’s net debt of $930 million as of June 30, 2018. At the election of each WildHorse common shareholder, the consideration will consist of either 5.989 shares of Chesapeake common stock or a combination of 5.336 shares of Chesapeake common stock and $3.00 in cash for each share of WildHorse common stock. We intend to fund the cash portion of the consideration through borrowings under our revolving credit facility. The transaction has been unanimously approved by the Board of Directors of each company and is subject to shareholder approvals from both companies and customary closing conditions and regulatory approvals and is expected to close in the first half of 2019.
On October 29, 2018, we completed the sale of our Utica Shale assets in Ohio to Encino, pursuant to which Encino purchased all of our approximately 1,500,000 gross (900,000 net) acres in Ohio, of which approximately 320,000 net acres are prospective for the Utica Shale with approximately 920 producing wells, along with related property and equipment (collectively, the “Designated Properties”) for net proceeds of $1.868 billion in cash.
On October 29, 2018, we delivered a notice of redemption to the trustee for our 8.00% Senior Secured Second Lien Notes due 2022 to call for redemption $1.416 billion aggregate principal amount of the outstanding notes, representing 100% of the aggregate principal amount of the outstanding notes. The notes will be redeemed at a redemption price of 100% of the principal amount thereof, plus the make-whole premium, as calculated in accordance with the indenture, plus accrued and unpaid interest. The settlement of the redemption is expected to occur approximately 30 days from the notice delivery date. The redemption is expected to be funded with proceeds from the sale of our Utica assets in Ohio.

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ITEM 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion should be read together with the condensed consolidated financial statements included in Item 1 of Part I of this report and our 2017 Form 10-K.
We are an independent exploration and production company engaged in the acquisition, exploration and development of properties for the production of oil, natural gas and NGL from underground reservoirs. We own a large and geographically diverse portfolio of onshore U.S. unconventional natural gas and liquids assets, including interests in approximately 14,900 oil and natural gas wells. We have leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas, the stacked pay in the Powder River Basin in Wyoming and the Anadarko Basin in northwestern Oklahoma. Our natural gas resource plays are the Marcellus Shale in the northern Appalachian Basin in Pennsylvania and the Haynesville/Bossier Shales in northwestern Louisiana and East Texas.
Our strategy is to create shareholder value through the development of our significant resource plays. We continue to focus on reducing debt, increasing cash provided by operating activities, and improving margins through financial discipline and operating efficiencies. Our capital program is focused on investments that can improve our cash flow generating ability even in a challenging commodity price environment. Although we expect our forecasted capital expenditures in 2018 to be lower compared to 2017, we anticipate modest production growth from both our oil-producing and natural gas-producing assets, adjusted for asset sales. Our ability to reduce capital expenditures while still growing production is primarily the result of improved drilling and completion efficiencies and improved well performance. We continue to seek opportunities to reduce cash costs (production, gathering, processing and transportation, general and administrative and interest expenses) and improve our production volumes from existing wells.
We believe that our dedication to financial discipline, the flexibility and efficiency of our capital program and cost structure and our continued focus on safety and environmental stewardship will provide opportunities to create value for us and our shareholders.
In 2018, our focus is concentrated on three strategic priorities:
•
reduce total debt by $2 - $3 billion;
•
increase net cash provided by operating activities to fund capital expenditures; and
•
improve margins through financial discipline and operating efficiencies.
On October 29, 2018 we completed the sale of all of our assets in Ohio. This divestiture will result in our meeting or making significant progress toward all three of these priorities. The following discussion and analysis presents management’s perspective of our business and material changes to our results of operations for the three and nine months ended September 30, 2018 compared to the three and nine months ended September 30, 2017 and in our financial condition and liquidity since December 31, 2017.
Overview
The transformation of Chesapeake over the past five years has been significant and our progress has continued in the Current Period. Our basic strategies have not changed through the price cycles of the past several years, and we believe our recent accomplishments and achievements in the Current Period have made our company stronger. Our progress has been guided by our strategies of financial discipline, pursuing profitable and efficient growth from our captured resources, leveraging technology and our operational expertise to unlock additional domestic resources and optimizing our portfolio through business development.

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We have made significant progress towards achieving our strategic priorities in 2018. So far we have:
•
entered into a definitive agreement to acquire WildHorse, an oil and gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas, in a transaction valued at approximately $3.977 billion;
•
sold our interests in the Utica Shale operating area located in Ohio for approximately $1.868 billion, with an additional contingent payment to us of up to $100 million based on future natural gas prices. We intend to use the net proceeds to reduce our indebtedness, including the redemption of our senior secured second lien notes, representing the remainder of our non-credit facility secured debt;
•
retired our secured term loan borrowings and significantly extended our debt maturity profile by issuing at par $850 million of 7.00% Senior Notes due 2024 and $400 million of 7.50% Senior Notes due 2026 pursuant to a public offering for net proceeds of $1.230 billion. We used the proceeds from these unsecured senior notes together with cash on hand and borrowings under our revolving credit facility, to repay in full $1.233 billion of borrowings under our secured term loan due 2021;
•
amended and restated our credit agreement dated December 15, 2014. The amended and restated revolving credit facility matures in September 2023 and the aggregate initial commitment of the lenders and borrowing base under the facility is $3.0 billion. The revolving credit facility provides for an accordion feature, pursuant to which the aggregate commitments thereunder may be increased to up to $4.0 billion from time to time, subject to agreement of the participating lenders and certain other customary conditions;
•
repurchased the CHK Utica, L.L.C. investors’ ORRI for $199 million in an effort to remove financial and operational complexity and to improve our balance sheet;
•
sold properties in the Mid-Continent, including our Mississippian Lime assets, for aggregate proceeds of approximately $500 million;
•
received net proceeds of approximately $74 million from the sale of approximately 4.3 million shares of FTS International, Inc. (NYSE: FTSI). FTSI is a provider of hydraulic fracturing services in North America and a company in which Chesapeake has owned a significant stake since 2006. FTSI completed its initial public offering of common shares on February 6, 2018. We currently own approximately 22.0 million shares of FTSI; and
•
reduced annual cash costs by approximately $70 million through a reduction in workforce that better aligns our workforce to the needs of our business.
We continue to benefit from progress made over the last five years, including removing financial and operational complexity, significantly improving our balance sheet and addressing numerous legacy issues.

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Financial Results
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
Change(b)
 
2018
 
2017
 
Change
 
($ in millions)
Net income (loss) available to common stockholders
$
60

 
$
(41
)
 
n/m

 
$
288

 
$
506

 
(43
)%
Net earnings (loss) per diluted common share
$
0.07

 
$
(0.05
)
 
n/m

 
$
0.32

 
$
0.56

 
(43
)%
Total production (mboe per day)
537

 
542

 
(1
)%
 
540

 
532

 
2
 %
Adjusted production(a) (mboe per day)
536

 
512

 
5
 %
 
534

 
494

 
8
 %
Average sales price (per boe)
$
26.92

 
$
21.06

 
28
 %
 
$
26.59

 
$
22.53

 
18
 %
Oil, natural gas and NGL production expenses
$
132

 
$
151

 
(13
)%
 
$
417

 
$
426

 
(2
)%
Oil, natural gas and NGL gathering, processing and transportation expenses
$
364

 
$
369

 
(1
)%
 
$
1,060

 
$
1,081

 
(2
)%
General and administrative expenses
$
66

 
$
54

 
22
 %
 
$
229

 
$
189

 
21
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30,
2018
 
December 31, 2017
 
Change
Total debt (principal amount)
 
 
 
 
$9,862
 
 
 
$9,981
 
(1
)%
___________________________________________
(a)
Adjusted for assets sold.
(b) n/m - not meaningful.

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Liquidity and Capital Resources
Liquidity Overview
Our ability to grow, make capital expenditures and service our debt depends primarily upon the prices we receive for the oil, natural gas and NGL we sell. Substantial expenditures are required to replace reserves, sustain production and fund our business plans. Historically, oil and natural gas prices have been volatile, and may be subject to wide fluctuations in the future. A decline in oil, natural gas and NGL prices could negatively affect the amount of cash we generate and have available for capital expenditures and debt service and could have a material impact on our financial position, results of operations, cash flows and on the quantities of reserves that we can economically produce or provide as collateral to our credit facility lenders. Other risks and uncertainties that could affect our liquidity include, but are not limited to, counterparty credit risk for our receivables, access to capital markets, regulatory risks and our ability to meet financial covenants in our financing agreements.
Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facility, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months.
As of September 30, 2018, we had a cash balance of $4 million compared to $5 million as of December 31, 2017, and we had a net working capital deficit of $1.741 billion as of September 30, 2018, compared to a net working capital deficit of $831 million as of December 31, 2017. As of September 30, 2018, our working capital deficit includes $432 million principal amount of debt due or that could be put to us in the next 12 months. As of September 30, 2018, we had $2.173 billion of borrowing capacity available under our senior secured revolving credit facility, with outstanding borrowings of $645 million and $182 million utilized for various letters of credit. See Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of our debt obligations, including principal and carrying amounts of our notes.
Even though we have taken measures to mitigate the liquidity concerns facing us for the next 12 months as outlined above and in Industry Outlook in our 2017 Form 10-K, there can be no assurance that these measures will be sufficient for periods beyond the next 12 months. If needed, we may seek to access the capital markets or otherwise refinance a portion of our outstanding indebtedness to improve our liquidity. We closely monitor the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our revolving credit facility. Furthermore, our ability to generate operating cash flow in the current commodity price environment, sell assets, access capital markets or take any other action to improve our liquidity and manage our debt is subject to the risks discussed above and elsewhere in our periodic reports and the other risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time or control.

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Derivative and Hedging Activities
Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL. To mitigate a portion of our exposure to adverse market changes, we have entered into various derivative instruments. Our oil, natural gas and NGL derivative activities, when combined with our sales of oil, natural gas and NGL, allow us to better predict the total revenue we expect to receive.
We utilize various oil, natural gas and NGL derivative instruments to protect a portion of our cash flow against downside risk. As of October 26, 2018, we have downside price protection in the remainder of 2018, 2019 and 2020 through the following oil, natural gas and NGL derivative instruments:
Oil Derivatives(a)
Year
 
Type of Derivative Instrument
 
Notional Volume
 
Average NYMEX Price
 
 
 
 
(mmbbls)
 
 
2018
 
Swaps
 
7

 
$54.09
2018
 
Three-way collars
 
1

 
$39.15/$47.00/$55.00
2018
 
Basis protection swaps
 
4

 
$3.52
2019
 
Swaps
 
14

 
$59.44
2019
 
Basis protection swaps
 
7

 
$6.01
2020
 
Swaps
 
3

 
$69.47
Natural Gas Derivatives(a)
Year
 
Type of Derivative Instrument
 
Notional Volume
 
Average NYMEX Price
 
 
 
 
(bcf)
 
 
2018
 
Swaps
 
120

 
$3.00
2018
 
Two-way collars
 
12

 
$3.00/$3.25
2018
 
Calls
 
17

 
$6.27
2018
 
Basis protection swaps
 
6

 
($0.77)
2019
 
Swaps
 
325

 
$2.83
2019
 
Two-way collars
 
54

 
$2.75/$3.02
2019
 
Three-way collars
 
88

 
$2.50/$2.80/$3.10
2019
 
Basis protection swaps
 
37

 
$0.03
2019
 
Calls
 
22

 
$12.00
2020
 
Calls
 
22

 
$12.00
NGL Derivatives(a)
Year
 
Type of Derivative Instrument
 
Notional Volume
 
Average NYMEX Price
 
 
 
 
(mmgal)
 
 
2018
 
Butane swaps
 
1

 
$0.88
2018
 
Butane % of WTI swaps
 
1

 
70.5% of WTI
2018
 
Propane swaps
 
15

 
$0.79
2018
 
Ethane swaps
 
23

 
$0.29
2018
 
Isobutane swaps
 
4

 
$0.92
2018
 
Natural gasoline
 
12

 
$1.42
___________________________________________
(a)
Includes amounts settled in October 2018 and excludes derivatives novated to Encino on October 29, 2018.
See Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of derivatives and hedging activities.

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Debt
We are committed to decreasing the amount of debt outstanding by $2-3 billion in 2018. To accomplish this objective, we intend to use the anticipated net proceeds from the pending sale of our Utica interests, allocate our capital expenditures to the highest-return projects, deploy leading drilling and completion technology throughout our portfolio to profitably and efficiently grow, and divest additional assets to strengthen our cost structure and our portfolio. We are seeking to reduce cash costs (production, gathering, processing and transportation, general and administrative and interest expenses), improve our production volumes from existing wells, and achieve additional operating and capital efficiencies with a focus on growing our oil volumes.
We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities and the proceeds from asset sales to retire our outstanding debt and/or preferred stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.
Revolving Credit Facility
In the Current Quarter, we amended and restated our senior secured revolving credit facility which is currently subject to a $3.0 billion borrowing base and matures in September 2023. As of September 30, 2018, we had $2.173 billion of borrowing capacity available under our revolving credit facility. Our next borrowing base redetermination is scheduled for the second quarter of 2019. As of September 30, 2018, we had outstanding borrowings of $645 million under the revolving credit facility and had used $182 million of the revolving credit facility for various letters of credit. Borrowings under the facility bear interest at a variable rate. See Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of this report for further discussion of the terms of the revolving credit facility. As of September 30, 2018, we were in compliance with all applicable financial covenants under the credit agreement. Our total leverage ratio was approximately 3.82 to 1.00, our first lien secured leverage ratio was approximately 0.32 to 1.00, our interest coverage ratio was approximately 3.51 to 1.00 and our debt to capitalization ratio was approximately 0.38 to 1.00.
Contractual Obligations and Off-Balance Sheet Arrangements
From time to time, we enter into arrangements and transactions that can give rise to contractual obligations and off-balance sheet commitments. As of September 30, 2018, these arrangements and transactions included (i) operating lease agreements, (ii) a volumetric production payment (VPP) (to purchase production and pay related production expenses and taxes in the future), (iii) open purchase commitments, (iv) open delivery commitments, (v) open drilling commitments, (vi) undrawn letters of credit, (vii) open gathering and transportation commitments, and (viii) various other commitments we enter into in the ordinary course of business that could result in a future cash obligation. See Notes 4 and 9 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of commitments and VPPs, respectively.
Capital Expenditures
Our 2018 capital expenditures program, while planned to be lower than our 2017 program, is expected to generate greater capital efficiency as we focus on expanding our margins by investing in the highest-return projects. We have significant control and flexibility over the timing and execution of our development plan, enabling us to reduce our capital spending as needed. Our forecasted 2018 capital expenditures, inclusive of capitalized interest, are $2.2 – $2.5 billion compared to our 2017 capital spending level of $2.5 billion. Management continues to review operational plans for 2018 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL.

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Credit Risk
Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as gathering, processing, transportation and hedging agreements. As of October 26, 2018, we have received requests and posted approximately $222 million of collateral related to certain of our marketing and other contracts. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $441 million, which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business relationships with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business arrangements and by offsetting amounts that the counterparty owes us. Any posting of collateral consisting of cash or letters of credit reduces availability under our revolving credit facility and negatively impacts our liquidity.
Sources of Funds
The following table presents the sources of our cash and cash equivalents for the Current Period and the Prior Period. See Note 9 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of divestitures of oil and natural gas assets.
 
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
 
($ in millions)
Cash provided by operating activities
 
$
1,595

 
$
273

Proceeds from divestitures of proved and unproved properties, net
 
395

 
1,193

Proceeds from issuance of senior notes, net
 
1,237

 
742

Proceeds from issuance of credit facility borrowings, net
 
—

 
645

Proceeds from sales of other property and equipment, net
 
75

 
40

Proceeds from sales of investments
 
74

 
—

Total sources of cash and cash equivalents
 
$
3,376

 
$
2,893

Cash Flow from Operating Activities
Cash provided by operating activities was $1.595 billion in the Current Period compared to cash used by operating activities of $273 million in the Prior Period. The increase in the Current Period is primarily due to the result of higher prices for the oil and NGL we sold and higher volumes of oil and natural gas sold. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and amortization, certain impairments, gains or losses on sales of fixed assets, deferred income taxes and mark-to-market changes in our open derivative instruments. See further discussion below under Results of Operations.

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Uses of Funds
The following table presents the uses of our cash and cash equivalents for the Current Period and the Prior Period:
 
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
 
($ in millions)
Oil and Natural Gas Expenditures:
 
 
 
 
Drilling and completion costs
 
$
1,481

 
$
1,597

Acquisitions of proved and unproved properties
 
123

 
87

Interest capitalized on unproved leasehold
 
121

 
139

Total oil and natural gas expenditures
 
1,725

 
1,823

Other Uses of Cash and Cash Equivalents:
 
 
 
 
Payments on revolving credit facility borrowings, net
 
136

 
—

Extinguishment of other financing
 
122

 
—

Cash paid to purchase debt
 
1,285

 
1,751

Additions to other property and equipment
 
11

 
12

Dividends paid
 
69

 
160

Other
 
29

 
24

Total other uses of cash and cash equivalents
 
1,652

 
1,947

Total uses of cash and cash equivalents
 
$
3,377

 
$
3,770

Drilling and Completion Costs
Our drilling and completion costs decreased in the Current Period compared to the Prior Period primarily as a result of lower rig and completion activity. During the Current Period, our average operated rig count was 17 rigs compared to an average operated rig count of 18 rigs in the Prior Period and we completed 242 operated wells in the Current Period compared to 326 in the Prior Period.
Extinguishment of Other Financing
In the Current Period, we repurchased previously conveyed overriding royalty interests (ORRIs) from the CHK Utica, L.L.C. investors and extinguished our obligation to convey future ORRIs to the investors for combined consideration of $199 million. The cash paid was bifurcated between extinguishment of the obligation and acquisition of the ORRI. See Note 5 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the transaction.
Repurchase and Repayment of Debt
In the Current Quarter, we used $1.285 billion of cash from the issuance of senior notes together with cash on hand and borrowings under our revolving credit facility to repay in full $1.233 billion principal amount of borrowings under our secured term loan due 2021 plus a call premium of $52 million. In the Prior Period, we used $1.751 billion of cash from debt issuances to repurchase $1.609 billion principal amount of debt.
Dividends
We paid dividends of $69 million on our preferred stock during the Current Period and we paid dividends of $160 million on our preferred stock in the Prior Period, including $92 million of dividends in arrears that had been suspended throughout 2016. We eliminated common stock dividends in the 2015 third quarter and do not anticipate paying any common stock dividends in the foreseeable future.

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Results of Operations
Oil, Natural Gas and NGL Production and Average Sales Prices
 
 
Three Months Ended September 30, 2018
 
 
Oil
 
Natural Gas
 
NGL
 
Total
 
 
mbbl
per day
 
$/bbl
 
mmcf
per day
 
$/mcf
 
mbbl
per day
 
$/bbl
 
mboe
per day
 
%
 
$/boe
Marcellus
 
—

 
—

 
812

 
2.46

 
—

 
—

 
135

 
25

 
14.74

Haynesville
 
—

 
—

 
769

 
2.74

 
—

 
—

 
128

 
24

 
16.44

Eagle Ford
 
58

 
74.40

 
122

 
3.26

 
22

 
28.95

 
100

 
19

 
53.43

Utica
 
10

 
67.09

 
488

 
2.92

 
28

 
29.39

 
119

 
22

 
24.33

Mid-Continent
 
9

 
69.41

 
66

 
2.50

 
4

 
29.40

 
25

 
5

 
37.68

Powder River Basin
 
12

 
69.23

 
73

 
2.50

 
5

 
27.89

 
29

 
5

 
39.79

Retained assets(a)
 
89

 
72.39

 
2,330

 
2.69

 
59

 
29.10

 
536

 
100

 
26.92

Divested assets
 
—

 
—

 
2

 
2.02

 
—

 
—

 
1

 
—

 
19.17

Total
 
89

 
72.39

 
2,332

 
2.69

 
59

 
29.09

 
537

 
100
%
 
26.92

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2017
 
 
Oil
 
Natural Gas
 
NGL
 
Total
 
 
mbbl
per day
 
$/bbl
 
mmcf
per day
 
$/mcf
 
mbbl
per day
 
$/bbl
 
mboe
per day
 
%
 
$/boe
Marcellus
 
—

 
—

 
748

 
1.96

 
—

 
—

 
125

 
23

 
11.76

Haynesville
 
—

 
—

 
804

 
2.77

 
—

 
—

 
134

 
25

 
16.63

Eagle Ford
 
52

 
49.08

 
136

 
3.25

 
18

 
23.07

 
92

 
17

 
36.91

Utica
 
12

 
44.18

 
475

 
2.76

 
28

 
20.30

 
120

 
22

 
20.21

Mid-Continent
 
10

 
46.98

 
69

 
2.54

 
6

 
22.18

 
27

 
5

 
28.03

Powder River Basin
 
5

 
47.12

 
35

 
2.91

 
3

 
26.77

 
14

 
2

 
31.01

Retained assets(a)
 
79

 
47.96

 
2,267

 
2.52

 
55

 
21.70

 
512

 
94

 
20.94

Divested assets
 
7

 
47.71

 
115

 
2.47

 
4

 
23.63

 
30

 
6

 
23.25

Total
 
86

 
47.94

 
2,382

 
2.52

 
59

 
21.83

 
542

 
100
%
 
21.06

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
 
Oil
 
Natural Gas
 
NGL
 
Total
 
 
mbbl
per day
 
$/bbl
 
mmcf
per day
 
$/mcf
 
mbbl
per day
 
$/bbl
 
mboe
per day
 
%
 
$/boe
Marcellus
 
—

 
—

 
829

 
2.85

 
—

 
—

 
138

 
26

 
17.13

Haynesville
 
—

 
—

 
811

 
2.72

 
—

 
—

 
135

 
25

 
16.34

Eagle Ford
 
60

 
70.33

 
135

 
3.26

 
19

 
26.90

 
102

 
19

 
50.79

Utica
 
10

 
63.39

 
446

 
2.88

 
26

 
26.65

 
111

 
20

 
23.78

Mid-Continent
 
9

 
66.08

 
67

 
2.51

 
5

 
26.63

 
25

 
5

 
36.02

Powder River Basin
 
10

 
67.01

 
59

 
2.48

 
4

 
27.86

 
23

 
4

 
38.31

Retained assets(a)
 
89

 
68.73

 
2,347

 
2.82

 
54

 
26.82

 
534

 
99

 
26.53

Divested assets
 
2

 
63.37

 
22

 
2.77

 
1

 
29.62

 
6

 
1

 
31.47

Total
 
91

 
68.63

 
2,369

 
2.82

 
55

 
26.87

 
540

 
100
%
 
26.59

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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Nine Months Ended September 30, 2017
 
 
Oil
 
Natural Gas
 
NGL
 
Total
 
 
mbbl
per day
 
$/bbl
 
mmcf
per day
 
$/mcf
 
mbbl
per day
 
$/bbl
 
mboe
per day
 
%
 
$/boe
Marcellus
 
—

 
—

 
796

 
2.52

 
—

 
—

 
132

 
25

 
15.14

Haynesville
 
—

 
—

 
736

 
2.90

 
—

 
—

 
123

 
23

 
17.39

Eagle Ford
 
55

 
49.42

 
140

 
3.36

 
18

 
21.27

 
96

 
18

 
37.22

Utica
 
9

 
44.01

 
410

 
3.12

 
26

 
20.87

 
104

 
19

 
21.54

Mid-Continent
 
8

 
47.43

 
69

 
2.85

 
5

 
21.02

 
25

 
5

 
27.65

Powder River Basin
 
6

 
48.12

 
34

 
3.06

 
3

 
24.52

 
14

 
3

 
31.58

Retained assets(a)
 
78

 
48.48

 
2,185

 
2.83

 
52

 
21.20

 
494

 
93

 
22.43

Divested assets
 
8

 
49.00

 
154

 
2.75

 
5

 
22.31

 
38

 
7

 
23.77

Total
 
86

 
48.53

 
2,339

 
2.83

 
57

 
21.28

 
532

 
100
%
 
22.53

___________________________________________
(a) Includes assets retained as of September 30, 2018.
Oil, Natural Gas and NGL Sales
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
 
($ in millions)
Oil
$
594

 
$
379

 
57
%
 
$
1,698

 
$
1,140

 
49
%
Natural gas
578

 
553

 
5
%
 
1,822

 
1,807

 
1
%
NGL
159

 
117

 
36
%
 
404

 
328

 
23
%
Oil, natural gas and NGL sales
$
1,331

 
$
1,049

 
27
%
 
$
3,924

 
$
3,275

 
20
%
The increase in the price received per boe in the Current Quarter resulted in a $291 million increase in revenues, and decreased sales volumes resulted in a $9 million decrease in revenues, for a total net increase in revenues of $282 million. The increase in the price received per boe in the Current Period resulted in a $599 million increase in revenues, and increased sales volumes resulted in a $50 million increase in revenues, for a total net increase in revenues of $649 million.
A change in oil, natural gas and NGL prices has a significant impact on our revenues and cash flows. Assuming our Current Quarter production levels and without considering the effect of derivatives, an increase or decrease of $1.00 per barrel of oil sold would have resulted in an increase or decrease in Current Quarter revenues and cash flows from operations of approximately $8 million, an increase or decrease of $0.10 per mcf of natural gas sold would have resulted in an increase or decrease in Current Quarter revenues and cash flows from operations of approximately $21 million and an increase or decrease of $1.00 per barrel of NGL sold would have resulted in an increase or decrease in Current Quarter revenues and cash flows from operations of approximately $5 million. Assuming our Current Period production levels and without considering the effect of derivatives, an increase or decrease of $1.00 per barrel of oil sold would have resulted in an increase or decrease in Current Period revenues and cash flows from operations of approximately $24 million, an increase or decrease of $0.10 per mcf of natural gas sold would have resulted in an increase or decrease in Current Period revenues and cash flows from operations of approximately $65 million and $64 million, respectively, and an increase or decrease of $1.00 per barrel of NGL sold would have resulted in an increase or decrease in Current Period revenues and cash flows from operations of approximately $15 million.


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Oil, Natural Gas and NGL Derivatives
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
2018
 
2017
 
($ in millions)
Oil derivatives – realized gains (losses)
$
(112
)
 
$
35

 
$
(273
)
 
$
79

Oil derivatives – unrealized gains (losses)
12

 
(96
)
 
(115
)
 
45

Total gains (losses) on oil derivatives
(100
)
 
(61
)
 
(388
)
 
124

 
 
 
 
 
 
 
 
Natural gas derivatives – realized gains (losses)
(1
)
 
(1
)
 
83

 
(53
)
Natural gas derivatives – unrealized gains (losses)
(17
)
 
(3
)
 
(168
)
 
384

Total gains (losses) on natural gas derivatives
(18
)
 
(4
)
 
(85
)
 
331

 
 
 
 
 
 
 
 
NGL derivatives – realized gains (losses)
(10
)
 
(3
)
 
(14
)
 
(1
)
NGL derivatives – unrealized gains (losses)
(4
)
 
(2
)
 
(13
)
 
(2
)
Total gains (losses) on NGL derivatives
(14
)
 
(5
)
 
(27
)
 
(3
)
Total gains (losses) on oil, natural gas and NGL derivatives
$
(132
)
 
$
(70
)
 
$
(500
)
 
$
452

See Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of this report for a discussion of our derivative activity.
Marketing Revenues and Expenses
In connection with the marketing of our production, we take title to the oil, natural gas and NGL we purchase from other working interest owners at defined delivery points and deliver the product to third parties, at which time revenues are recorded. In circumstances where we act as a principal rather than an agent, revenue is presented on a gross basis. Marketing revenues primarily consist of marketing services, including commodity price structuring, securing and negotiating gathering, hauling, processing and transportation services, contract administration and nomination services for Chesapeake and other interest owners in Chesapeake-operated wells.
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
 
($ in millions)
Marketing revenues
$
1,219

 
$
964

 
26
 %
 
$
3,738

 
$
3,250

 
15
%
Marketing expenses
1,238

 
978

 
27
 %
 
3,798

 
3,333

 
14
%
Marketing gross margin
$
(19
)
 
$
(14
)
 
(36
)%
 
$
(60
)
 
$
(83
)
 
28
%
Marketing revenues and expenses increased in the Current Quarter and the Current Period primarily as a result of increased oil, natural gas and NGL prices received in our marketing operations.

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Oil, Natural Gas and NGL Production Expenses
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
 
($ in millions)
Marcellus
$
8

 
$
7

 
14
 %
 
$
23

 
$
17

 
35
 %
Haynesville
15

 
16

 
(6
)%
 
45

 
38

 
18
 %
Eagle Ford
41

 
51

 
(20
)%
 
141

 
142

 
(1
)%
Utica
11

 
11

 
—
 %
 
33

 
30

 
10
 %
Mid-Continent
29

 
29

 
—
 %
 
78

 
82

 
(5
)%
Powder River Basin
12

 
7

 
71
 %
 
35

 
21

 
67
 %
Retained Assets(a)
116

 
121

 
(4
)%
 
355

 
330

 
8
 %
Divested Assets
—

 
18

 
(100
)%
 
14

 
60

 
(77
)%
Total
116

 
139

 
(17
)%
 
369

 
390

 
(5
)%
 
 
 
 
 
 
 
 
 
 
 
 
Ad valorem tax
16

 
12

 
33
 %
 
48

 
36

 
33
 %
 
 
 
 
 
 
 
 
 
 
 
 
Total oil, natural gas and NGL production expenses
$
132

 
$
151

 
(13
)%
 
$
417

 
$
426

 
(2
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
($ per boe)
Marcellus
$
0.62

 
$
0.58

 
7
 %
 
$
0.61

 
$
0.46

 
33
 %
Haynesville
$
1.28

 
$
1.27

 
1
 %
 
$
1.21

 
$
1.12

 
8
 %
Eagle Ford
$
4.52

 
$
6.10

 
(26
)%
 
$
5.08

 
$
5.41

 
(6
)%
Utica
$
0.98

 
$
0.98

 
—
 %
 
$
1.10

 
$
1.06

 
4
 %
Mid-Continent
$
12.95

 
$
11.44

 
13
 %
 
$
11.37

 
$
11.98

 
(5
)%
Powder River Basin
$
4.39

 
$
5.89

 
(25
)%
 
$
5.47

 
$
5.56

 
(2
)%
Retained Assets(a)
$
2.36

 
$
2.57

 
(8
)%
 
$
2.43

 
$
2.44

 
—
 %
Divested Assets
$
—

 
$
6.47

 
(100
)%
 
$
8.19

 
$
5.83

 
40
 %
Total
$
2.36

 
$
2.79

 
(15
)%
 
$
2.50

 
$
2.68

 
(7
)%
 
 
 
 
 
 
 
 
 
 
 
 
Ad valorem tax
$
0.32

 
$
0.24

 
33
 %
 
$
0.33

 
$
0.25

 
32
 %
 
 
 
 
 


 
 
 
 
 
 
Total oil, natural gas and NGL production expenses per boe
$
2.68

 
$
3.03

 
(12
)%
 
$
2.83

 
$
2.93

 
(3
)%
___________________________________________
(a) Includes assets retained as of September 30, 2018.
The absolute and per unit decrease in the Current Quarter was the result of decreased workover activity in Eagle Ford and the sale of certain oil and natural gas properties in 2017 and 2018. The absolute and per unit decrease in the Current Period was the result of the sale of certain oil and natural gas properties in 2017 and 2018.
Production expenses in the Current Quarter, the Prior Quarter, the Current Period and the Prior Period included approximately $4 million, $5 million, $12 million and $15 million associated with VPP production volumes, respectively. We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our remaining VPP agreement decrease and operating efficiencies generally improve.

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Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
2018
 
2017
 
($ in millions, except per unit)
Oil, natural gas and NGL gathering, processing and transportation expenses
$
364

 
$
369

 
$
1,060

 
$
1,081

Oil ($ per bbl)
$
3.83

 
$
4.33

 
$
3.75

 
$
3.96

Natural gas ($ per mcf)
$
1.33

 
$
1.34

 
$
1.30

 
$
1.36

NGL ($ per bbl)
$
8.59

 
$
7.40

 
$
8.62

 
$
7.90

Total ($ per boe)
$
7.36

 
$
7.40

 
$
7.18

 
$
7.43

The absolute and per unit decrease in oil, natural gas and NGL gathering, processing and transportation expenses was primarily due to lower gathering fees associated with restructured midstream contracts, lower volume commitments on downstream pipelines and certain 2017 and 2018 divestitures.
Production Taxes
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
 
($ in millions, except per unit)
Production taxes
$
34

 
$
21

 
62
%
 
$
91

 
$
64

 
42
%
Production taxes per boe
$
0.69

 
$
0.43

 
60
%
 
$
0.62

 
$
0.44

 
41
%
The absolute and per unit increase in production taxes was primarily due to higher prices received for our oil, natural gas and NGL production.
General and Administrative Expenses
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
 
($ in millions, except per unit)
Gross overhead
$
175

 
$
187

 
(6
)%
 
$
564

 
$
595

 
(5
)%
Allocated to production expenses
(36
)
 
(45
)
 
(20
)%
 
(112
)
 
(135
)
 
(17
)%
Allocated to marketing expenses
(5
)
 
(7
)
 
(29
)%
 
(16
)
 
(23
)
 
(30
)%
Capitalized
(31
)
 
(35
)
 
(11
)%
 
(93
)
 
(103
)
 
(10
)%
Reimbursed from third parties
(37
)
 
(46
)
 
(20
)%
 
(114
)
 
(145
)
 
(21
)%
General and administrative expenses, net
$
66

 
$
54

 
22
 %
 
$
229

 
$
189

 
21
 %
 
 
 
 
 
 
 
 
 
 
 
 
General and administrative expenses, net per boe
$
1.34

 
$
1.08

 
24
 %
 
$
1.55

 
$
1.30

 
19
 %
Gross overhead decreased primarily due to our reduction in workforce. The absolute and per unit net expense increase was primarily due to less overhead allocated to production expenses, marketing expenses and capitalized general and administrative costs, as well as less overhead billed to third party working interest owners, due to certain divestitures in 2017 and 2018.

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Restructuring and Other Termination Costs
On January 30, 2018, we underwent a reduction in workforce impacting approximately 13% of employees across all functions, primarily on our Oklahoma City campus. In connection with the reduction, we incurred a total charge of approximately $38 million in the Current Period for one-time termination benefits. The charge consisted of $33 million in salary expense and $5 million of other termination benefits.
Oil, Natural Gas and NGL Depreciation, Depletion and Amortization
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
 
($ in millions, except per unit)
Oil, natural gas and NGL depreciation, depletion and amortization
$
274

 
$
228

 
20
%
 
$
813

 
$
627

 
30
%
Oil, natural gas and NGL depreciation, depletion and amortization per boe
$
5.54

 
$
4.57

 
21
%
 
$
5.51

 
$
4.31

 
28
%
The absolute and per unit increase in the Current Quarter and the Current Period is primarily the result of a higher depletion rate per boe coupled with an increase in production. The depletion rate per boe is a function of capitalized costs, future development costs, and the related underlying reserves in the periods presented. The increase in depletion rate per boe primarily reflects a downward revision in proved reserve estimates in the fourth quarter of 2017 due to an updated development plan in the Eagle Ford aligning up-spacing, our activity schedule and well performance. The downward revision in proved reserves was partially offset by the effect of upward price revisions as a result of improved trailing 12-month oil, natural gas and NGL prices, net of differentials.
Depreciation and Amortization of Other Assets
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
 
($ in millions, except per unit)
Depreciation and amortization of other assets
$
17

 
$
20

 
(15
)%
 
$
54

 
$
62

 
(13
)%
Depreciation and amortization of other assets per boe
$
0.35

 
$
0.41

 
(15
)%
 
$
0.37

 
$
0.43

 
(14
)%
The absolute and per unit decrease in the Current Quarter and the Current Period was primarily the result of the sale of certain other assets.
Impairments
We determined that certain of our other fixed assets will either be sold or disposed before the end of their useful lives indicating the carrying value may not be recoverable. As a result, we recognized impairment losses of $5 million, $3 million, $51 million and $3 million in the Current Quarter, Prior Quarter, Current Period and the Prior Period, respectively, for the difference between the carrying amount and fair value of the assets.
Other Operating (Income) Expense
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
 
($ in millions)
Other operating (income) expense
$
—

 
$
6

 
(100
)%
 
$
(1
)
 
$
423

 
(100
)%
In the Prior Period, we terminated future natural gas gathering transportation commitments related to divested assets for cash payments of $126 million. In the Prior Period, we also paid $290 million to assign an oil transportation agreement to a third party.

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Interest Expense
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
2018
 
2017
 
($ in millions)
Interest expense on senior notes
$
146

 
$
135

 
$
434

 
$
407

Interest expense on term loan
29

 
34

 
87

 
98

Amortization of loan discount, issuance costs and other
7

 
13

 
17

 
28

Amortization of premium
(24
)
 
(29
)
 
(72
)
 
(112
)
Interest expense on revolving credit facility
11

 
11

 
29

 
28

Realized gains on interest rate derivatives
(1
)
 
(1
)
 
(2
)
 
(3
)
Unrealized losses on interest rate derivatives
1

 
—

 
2

 
3

Capitalized interest
(42
)
 
(49
)
 
(128
)
 
(147
)
Total interest expense
$
127

 
$
114

 
$
367

 
$
302

 
 
 
 
 
 
 
 
Interest expense per boe(a)
$
2.56

 
$
2.26

 
$
2.48

 
$
2.05

 
 
 
 
 
 
 
 
Average senior notes borrowings
$
8,021

 
$
7,632

 
$
7,985

 
$
7,640

Average credit facilities borrowings
$
642

 
$
631

 
$
540

 
$
330

Average term loan borrowings
$
1,179

 
$
1,500

 
$
1,215

 
$
1,500

___________________________________________
(a)
Includes the effects of realized (gains) losses from interest rate derivatives, excludes the effects of unrealized (gains) losses from interest rate derivatives and is shown net of amounts capitalized.
The increase in interest expense is primarily due to the increase in the average outstanding principal amount of senior notes and a decrease in amortization of premium and capitalized interest. The decrease in amortization of premium is due to the decrease in the average outstanding principal amount of our senior secured second lien notes. The decrease in capitalized interest is a result of lower average balances of unproved oil and natural gas properties, the primary asset on which interest is capitalized. See Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of this report for a discussion of our debt refinancing.
Gains on Investments
In the Current Period, we recognized $139 million of gains related to our equity investment in FTSI, including the sale of a portion of that investment. See Note 11 of the notes to our condensed consolidated financial statements included in Item 1 of this report for further discussion.
Losses on Purchases or Exchanges of Debt
In the Current Quarter, we used the proceeds from the issuance of senior notes together with cash on hand and borrowings under our revolving credit facility, to repay in full $1.233 billion of borrowings under our secured term loan due 2021 for $1.285 billion including a call premium of $52 million. We recorded a loss of approximately $65 million associated with the repayment of the term loan, including the call premium and write-off of $13 million of associated deferred charges. Also in the Current Quarter, we recorded a loss of $3 million associated with certain deferred charges related to the revolving credit facility prior to its amendment. See Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of this report for a discussion of our debt refinancing.
In the Prior Quarter, we repurchased $5 million principal amount of our outstanding senior notes and contingent convertible senior notes for $6 million. We recorded an aggregate loss of approximately $1 million associated with the transaction.

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In the Prior Period, we retired $1.609 billion principal amount of our outstanding senior notes, senior secured second lien notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $1.751 billion, which included the maturity of our 6.25% Euro-denominated Senior Notes due 2017 and the corresponding cross currency swap. We recorded an aggregate net gain of approximately $183 million associated with the repurchases and tender offers.
Other Income (Expense)
In the Current Period, we extinguished our obligation to convey future ORRIs to the CHK Utica L.L.C. investors and recognized a $61 million gain included in other income on our condensed consolidated statement of operations. See Note 5 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of the transaction.
Income Tax Expense (Benefit)
We recorded a $1 million income tax expense in the Current Quarter and an $8 million income tax benefit in the Current Period and recorded a nominal amount of income tax benefit in the Prior Quarter and $2 million of income tax expense in the Prior Period. Our effective income tax rate was 1.2% for the Current Quarter and (2.3%) for the Current Period compared to 0.0% and 0.3% for the Prior Quarter and for the Prior Period, respectively. Our effective tax rate can fluctuate as a result of the impact of discrete items, state income taxes and permanent differences. For the Current Quarter, our estimated annual effective tax rate remains nominal as a result of having a full valuation allowance against our net deferred tax asset. See Note 6 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of income tax expense.
Forward-Looking Statements
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). Forward-looking statements include our current expectations or forecasts of future events, including matters relating to the acquisition of WildHorse, our ability to meet debt service requirements and the other items discussed in the Introduction to Item 2 of this report. In this context, forward-looking statements often address our expected future business, financial performance and financial condition, and often contain words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy.”
Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include:
•
the volatility of oil, natural gas and NGL prices;
•
uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures;
•
our ability to replace reserves and sustain production;
•
drilling and operating risks and resulting liabilities;
•
our ability to generate profits or achieve targeted results in drilling and well operations;
•
the limitations our level of indebtedness may have on our financial flexibility;
•
our inability to access the capital markets on favorable terms;
•
the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations;

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•
adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims;
•
effects of environmental protection laws and regulation on our business;
•
terrorist activities and/or cyber-attacks adversely impacting our operations;
•
effects and risks of acquisitions and dispositions, including the WildHorse Merger;
•
effects of purchase price adjustments and indemnity obligations;
•
the need to obtain certain consents and approvals and satisfy certain conditions to closing of the Utica transaction, which may not be completed in the anticipated time frame or at all;
•
failure to consummate the WildHorse acquisition; and
•
other factors that are described under Risk Factors in Part II, Item 1A of this report and Item 1A of our 2017 Form 10-K.
We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation to update this information. We urge you to carefully review and consider the disclosures in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.
ITEM 3.
Quantitative and Qualitative Disclosures About Market Risk
Oil, Natural Gas and NGL Derivatives
Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. Our oil, natural gas and NGL derivative activities, when combined with our sales of oil, natural gas and NGL, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.
Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse oil, natural gas and NGL price changes is to hedge into strengthening oil, natural gas and NGL futures markets when prices reach levels that management believes are unsustainable for the long term, have material downside risk in the short term or provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in our risk management activities and the Board of Directors reviews our derivative program at quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized trading.
We use derivative instruments to achieve our risk management objectives, including swaps, collars and options. All of these are described in more detail below. We typically use swaps and collars for a large portion of the oil and natural gas price risk we hedge. We have also sold calls, taking advantage of premiums associated with market price volatility.
We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would be reversed. The actual fixed price on our derivative instruments is derived from the reference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.

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We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering into a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter into the original derivative position. Gains or losses related to closed positions will be recognized in the month specified in the original contract.
We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our commodity hedging arrangements that require counterparties to post collateral if their obligations to us are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the fair value measurements associated with our derivatives.
As of September 30, 2018, our oil, natural gas and NGL derivative instruments consisted of the following types of instruments:
•
Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options and call swaptions.
•
Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
•
Call Swaptions: We sell call swaptions to counterparties that allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time
•
Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.
•
Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.

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As of September 30, 2018, we had the following open oil, natural gas and NGL derivative instruments:
 
 
 
 
Weighted Average Price
 
Fair Value
 
 
Volume
 
Fixed
 
Call
 
Put
 
Differential
 
Asset
(Liability)
 
 
(mmbbl)
 
($ per bbl)
 
($ in millions)
Oil:
 
 
 
 
 
 
 
 
 
 
 
 
Swaps:
 
 
 
 
 
 
 
 
 
 
 
 
Short-term
 
18

 
$
57.43

 
$
—

 
$
—

 
$
—

 
$
(265
)
Long-term
 
3

 
$
59.96

 
$
—

 
$
—

 
$
—

 
(29
)
Three-Way Collars:
 
 
 
 
 
 
 
 
 
 
 
 
Short-term
 
—

 
$
—

 
$
55.00

 
39.15/47.00

 
$
—

 
(8
)
Basis Protection Swaps:
 
 
 
 
 
 
 
 
 
 
 
 
Short-term
 
7

 
$
—

 
$
—

 
$
—

 
$
4.75

 
—

Long-term
 
1

 
$
—

 
$
—

 
$
—

 
$
6.20

 
2

Total Oil
 
(300
)
 
 
(bcf)
 
($ per mcf)
 

Natural Gas:
 
 
 
 
 
 
 
 
 
 
 
 
Swaps(a):
 
 
 
 
 
 
 
 
 
 
 
 
Short-term(b)
 
372

 
$
2.79

 
$
—

 
$
—

 
$
—

 
(19
)
Long-term
 
28

 
$
2.77

 
$
—

 
$
—

 
$
—

 
—

Three-Way Collars:
 
 
 
 
 
 
 
 
 
 
 
 
Short-term
 
66

 
$
—

 
$
3.10

 
2.50/2.80

 
—

 
3

Long-term
 
22

 
$
—

 
$
3.10

 
2.50/2.80

 
—

 
—

Collars:
 
 
 
 
 
 
 
 
 
 
 
 
Short-term
 
57

 
$
—

 
$
3.09

 
$
2.80

 
$
—

 
—

Long-term
 
9

 
$
—

 
$
2.91

 
$
2.75

 
$
—

 
—

Call Options (sold):
 
 
 
 
 
 
 
 
 
 
 
 
Short-term
 
33

 
$
—

 
$
9.12

 
$
—

 
$
—

 
—

Long-term
 
27

 
$
—

 
$
12.00

 
$
—

 
$
—

 
—

Basis Protection Swaps:
 
 
 
 
 
 
 
 
 
 
 
 
Short-term
 
38

 
$
—

 
$
—

 
$
—

 
$
(0.02
)
 
(7
)
Long-term
 
6

 
$
—

 
$
—

 
$
—

 
$
(0.39
)
 
—

Total Natural Gas
 
(23
)

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Weighted Average Price
 
Fair Value
 
 
Volume
 
Fixed
 
Call
 
Put
 
Differential
 
Asset
(Liability)
 
 
 
 
 
 
 
 
 
(mmgal)
 
($ per gal)
 
 
NGL:
 
 
 
 
 
 
 
 
 
 
 
 
Propane Swaps:
 
 
 
 
 
 
 
 
 
 
 
 
Short-term
 
16

 
$
0.79

 
$
—

 
$
—

 
$
—

 
(4
)
Butane Swaps:
 
 
 
 
 
 
 
 
 
 
 
 
Short-term
 
1

 
$
0.88

 
$
—

 
$
—

 
$
—

 
(1
)
Short-term % of WTI
 
1

 
70.50%

 
$
—

 
$
—

 
$
—

 
—

Isobutane Swaps:
 
 
 
 
 
 
 
 
 
 
 
 
Short-term
 
4

 
$
0.92

 
$
—

 
$
—

 
$
—

 
(1
)
Ethane Swaps:
 
 
 
 
 
 
 
 
 
 
 
 
Short-term
 
23

 
$
0.29

 
$
—

 
$
—

 
$
—

 
(6
)
Natural Gasoline Swaps:
 
 
 
 
 
 
 
 
 
 
 
Short-term
 
12

 
$
1.42

 
$
—

 
$
—

 
$
—

 
(3
)
Total NGL
 
(15
)
Total Estimated Fair Value
 
$
(338
)
___________________________________________
(a)
This amount includes a sold option to enhance the swap price at an average price of $3.40/mcf covering 11 bcf, included in the sold call options.
(b)
Includes 170 bcf related to trades executed in accordance with the purchase and sale agreement with Encino.  These trades are reflected at fair market value as of September 30, 2018, with an offsetting receivable balance. The trades were novated to Encino upon closing of the purchase and sale agreement on October 29, 2018.
In addition to the open derivative positions disclosed above, as of September 30, 2018, we had $63 million of net derivative losses related to settled contracts for future periods that will be recorded within oil, natural gas and NGL revenues as realized gains (losses) on derivatives once they are transferred from either accumulated other comprehensive income or unrealized gains (losses) on derivatives in the month specified in the original contract as noted below:
 
 
September 30,
2018
 
 
($ in millions)
Short-term
 
$
(24
)
Long-term
 
(39
)
Total
 
$
(63
)
The table below reconciles the changes in fair value of our oil and natural gas derivatives during the Current Period. Of the $338 million fair value liability as of September 30, 2018, a $310 million liability relates to contracts maturing in the next 12 months and a $28 million liability relates to contracts maturing after 12 months. All open derivative instruments as of September 30, 2018 are expected to mature by December 31, 2020.
 
 
September 30,
2018
 
 
($ in millions)
Fair value of contracts outstanding, as of January 1, 2018
 
$
(35
)
Change in fair value of contracts
 
(117
)
Contracts realized or otherwise settled
 
(186
)
Fair value of contracts outstanding, as of September 30, 2018
 
$
(338
)

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Interest Rate Risk
The table below presents principal cash flows and related weighted average interest rates by expected maturity dates, using the earliest demand repurchase date for contingent convertible senior notes.
 
Years of Maturity
 
 
 
2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
 
Total
 
($ in millions)
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt – fixed rate
$
53

 
$
—

 
$
664

 
$
815

 
$
1,867

 
$
5,438

 
$
8,837

Average interest rate
6.42
%
 
—
%
 
6.71
%
 
5.88
%
 
7.25
%
 
7.09
%
 
6.98
%
Debt – variable rate
$
—

 
$
380

 
$
—

 
$
—

 
$
—

 
$
645

 
$
1,025

Average interest rate
—
%
 
5.59
%
 
—
%
 
—
%
 
—
%
 
4.21
%
 
4.72
%
Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our revolving credit facility and our floating rate senior notes. All of our other indebtedness is fixed rate and, therefore, does not expose us to the risk of fluctuations in earnings or cash flow due to changes in market interest rates. However, changes in interest rates do affect the fair value of our fixed-rate debt.
As of September 30, 2018, we had $5 million of net gains related to settled interest rate derivative contracts that will be recorded within interest expense as realized gains or losses once they are transferred from our senior note liability or within interest expense as unrealized gains or losses over the remaining six-year term of our related senior notes.
Realized and unrealized (gains) or losses from interest rate derivative transactions are reflected as adjustments to interest expense on the consolidated statements of operations.
ITEM 4.
Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded as of September 30, 2018 that our disclosure controls and procedures were effective.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION
ITEM 1.
Legal Proceedings
There have been no material developments in previously reported legal or environmental proceedings. For a description of certain legal and regulatory proceedings affecting us, see “Contingencies and Commitments,” Note 4 to the Consolidated Financial Statements included in Item 1 of Part 1 of this report and Item 3 in our 2017 Form 10-K and in Note 4 to the Consolidated Financial Statements in our Form 10-Q for the quarterly periods ended March 31, 2018 and June 30, 2018.
ITEM 1A.
Risk Factors
Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock, preferred stock or senior notes are described under “Risk Factors” in Item 1A of our 2017 Form 10-K. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.
Our acquisition of WildHorse is subject to conditions, including certain conditions that may not be satisfied, or completed on a timely basis, if at all. Failure to complete the acquisition of WildHorse could have a material and adverse effect on us.
Completion of our acquisition of WildHorse is subject to a number of conditions set forth in our merger agreement with WildHorse, including the approval by our shareholders of the issuance of shares of our common stock as acquisition consideration and approval by WildHorse stockholders of the adoption of the merger agreement, which make the completion and timing of the completion of the transactions uncertain. Also, either we or WildHorse may terminate the merger agreement if the WildHorse Merger has not been consummated by May 31, 2019 (or, at either party’s discretion, if any governmental entity having jurisdiction over either us or WildHorse has issued any order, decree, ruling or injunction or taken any other action permanently restraining, enjoining or otherwise prohibiting the consummation of the WildHorse Merger).
If the transactions contemplated by the merger agreement are not completed, our ongoing business may be adversely affected and, without realizing any of the benefits of having completed the transactions, we will be subject to a number of risks, including the following:
•
we will be required to pay our costs relating to the transactions, such as legal, accounting, financial advisory and printing fees, whether or not the transactions are completed;
•
time and resources committed by our management to matters relating to the transactions could otherwise have been devoted to pursuing other beneficial opportunities, and our ongoing business and financial results may be adversely affected;
•
the market price of our common stock could decline to the extent that the current market price reflects a market assumption that the transactions will be completed;
•
being required to pay a termination fee or expense reimbursement fee of $120 million or $35 million, respectively, under certain circumstances provided in the merger agreement;
•
the manner in which customers, vendors, business partners and other third parties perceive us may be negatively impacted, which in turn could affect our marketing operations or our ability to compete for new business or obtain renewals in the marketplace more broadly;
•
we may experience negative reactions from employees; and
•
if the merger agreement is terminated and our board of directors seeks another acquisition, our shareholders cannot be certain that we will be able to find a party willing to enter into a transaction as attractive to us as the acquisition of WildHorse.
The WildHorse Merger may not be accretive, and may be dilutive, to our earnings per share, which may negatively affect the market price of shares on our common stock.
 Because shares of our common stock will be issued in the WildHorse Merger, it is possible that the WildHorse Merger may be dilutive to our earnings per share, which could negatively affect the market price of shares of our common stock.
In connection with the completion of the WildHorse Merger, the two largest shareholders of WildHorse, who together own approximately 70% of WildHorse common stock, have agreed to accept consideration of $3.00 per share of cash and 5.336 shares of Chesapeake common stock in exchange for each share of WildHorse common stock. The other WildHorse shareholders will have a choice of receiving a combination of $3.00 per share in cash and 5.336 shares of Chesapeake common stock, or 5.989 shares of Chesapeake common stock, for each share of WildHorse common stock. As a result, based on the number of issued and outstanding shares of WildHorse common stock as of October 29, 2018, we will issue up to 745 million shares of our common stock. The issuance of these new shares of

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our common stock could have the effect of depressing the market price of shares of our common stock, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, our earnings per share could cause the price of shares of our common stock to decline or increase at a reduced rate.
Our stockholders will be diluted by the WildHorse Merger.
The WildHorse Merger will dilute the ownership position of our current stockholders. As a result of issuances in connection with the WildHorse Merger, current stockholders of ours and WildHorse stockholders are expected to hold approximately 55% and 45%, respectively, of the combined company’s outstanding common stock immediately following completion of the WildHorse Merger, depending on the consideration elected.
The market price of shares of our common stock may decline in the future as a result of the sale of shares of our common stock held by former WildHorse stockholders or current stockholders.
Following their receipt of shares of our common stock as acquisition consideration in the WildHorse Merger, former WildHorse stockholders may, following 60 and 180 day lock-up periods for certain primary former stockholders, seek to sell the shares of our common stock delivered to them following the consummation of the WildHorse Merger. Other shareholders may also seek to sell shares of our common stock held by them following, or in anticipation of, completion of the WildHorse Merger. In addition, we have granted certain stockholders of WildHorse registration rights with respect to the shares of our common stock they receive in the WildHorse Merger. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of our common stock, may affect the market for, and the market price of, our common stock in an adverse manner.
We and WildHorse will be subject to business uncertainties while the WildHorse Merger is pending, which could adversely affect our respective businesses.
 Uncertainty about the effect of the WildHorse Merger on employees and customers may have an adverse effect on us and WildHorse. These uncertainties may impair our and WildHorse’s ability to attract, retain and motivate key personnel until the WildHorse Merger is completed and for a period of time thereafter and could cause customers and others that deal with us and WildHorse to seek to change their existing business relationships with us and WildHorse, respectively. Employee retention at WildHorse may be particularly challenging during the pendency of the WildHorse Merger, as employees may experience uncertainty about their roles with us following the WildHorse Merger. In addition, the merger agreement restricts us and WildHorse from entering into certain corporate transactions and taking other specified actions without the consent of the other party, and generally requires each party to continue its operations in the ordinary course of business, until completion of the WildHorse Merger. These restrictions may prevent us and WildHorse from pursuing attractive business opportunities that may arise prior to the completion of the WildHorse Merger.
We have substantial indebtedness, and following the WildHorse Merger, will continue to have substantial indebtedness.
At September 30, 2018, we had approximately $9.812 billion of indebtedness and at June 30, 2018, WildHorse had approximately $930 million of outstanding indebtedness. We continue to review the treatment of our and WildHorse’s existing indebtedness, and we may seek to repay, refinance, repurchase, redeem, exchange or otherwise terminatea portion of our or WildHorse’s existing indebtedness prior to, in connection with or following the completion of the WildHorse Merger. If we do seek to refinance our or WildHorse’s existing indebtedness, there can be no guarantee that we would be able to execute the refinancing on favorable terms or at all.
Any increase in our level of indebtedness could have adverse effects on our financial condition and results of operations, including:
•
imposing additional cash requirements on us in order to support interest payments, which reduces the amount we have available to fund our operations and other business activities;
•
increasing the risk that we may default on our debt obligations;
•
increasing our vulnerability to adverse changes in general economic and industry conditions, economic downturns and adverse developments in our business;
•
limiting our ability to sell assets, engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes;

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•
limiting our flexibility in planning for or reacting to changes in our business and the industry in which we operate; and
•
increasing our exposure to a rise in interest rates, which will generate greater interest expense to the extent we do not have applicable interest rate fluctuation hedges.
Even if we and WildHorse complete the WildHorse Merger, we may fail to realize all of the anticipated benefits of the WildHorse Merger. 
The success of the WildHorse Merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and WildHorse’s businesses, including operational and other synergies that we believe the combined company will achieve. The anticipated benefits and cost savings of the WildHorse Merger may not be realized fully or at all, may take longer to realize than expected or could have other adverse effects that we do not currently foresee. Some of the assumptions that we have made, such as the achievement of operating synergies, may not be realized. The integration process may, for us and WildHorse, result in the loss of key employees, the disruption of ongoing businesses or inconsistencies in standards, controls, procedures and policies. There could be potential unknown liabilities and unforeseen expenses associated with the WildHorse Merger that were not discovered in the course of performing due diligence. The integration will require significant time and focus from management following the acquisition.
We and WildHorse will incur substantial transaction fees and costs in connection with the WildHorse Merger.
 We and WildHorse expect to incur a number of non-recurring transaction-related costs associated with completing the WildHorse Merger, combining the operations of the two organizations and achieving desired synergies. These fees and costs will be substantial. Non-recurring transaction costs include, but are not limited to, fees paid to legal, financial and accounting advisors, filing fees and printing costs. Additional unanticipated costs may be incurred in the integration of WildHorse’s business with our business. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction-related costs over time. Thus, any net benefit of the WildHorse Merger may not be achieved in the near term, the long term or at all.
The exchange ratio is fixed and will not be adjusted in the event of any change in either our or WildHorse’s stock price.
At the effective time, each share of WildHorse common stock outstanding immediately prior to the effective time will be converted into the right to receive 5.989 shares of our common stock or 5.336 shares of our common stock and $3.00, at the election of the holder. This exchange ratio will not be adjusted for changes in the market price of either our common stock or WildHorse common stock between the date of signing the merger agreement and completion of the WildHorse Merger. Changes in the price of our common stock prior to the WildHorse Merger will affect the value of our common stock that WildHorse common stockholders will receive on the date of the WildHorse Merger.
The prices of our common stock and WildHorse common stock at the closing of the WildHorse Merger may vary from their prices on the date the merger agreement was executed and on the date of each special meeting. As a result, the value represented by the exchange ratio will also vary, and you will not know or be able to calculate the market value of the merger consideration you will receive upon completion of the WildHorse Merger.
We and WildHorse may be targets of securities class action and derivative lawsuits which could result in substantial costs and may delay or prevent the WildHorse Merger from being completed.
 Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements. Even if the lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our and WildHorse’s respective liquidity and financial condition. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the WildHorse Merger, then that injunction may delay or prevent the WildHorse Merger from being completed, which may adversely affect our and WildHorse’s respective business, financial position and results of operations.

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The issuance of our common stock to shareholders of WildHorse as well as other stock transactions can lead to an ownership change under Section 382 of the Internal Revenue Code.
    Our ability to utilize U.S. net operating loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited under Section 382 of the Code upon the occurrence of ownership changes resulting from issuances of our stock or the sale or exchange of our stock by certain shareholders if, as a result, there is a cumulative change of more than 50% in the beneficial ownership of our stock during any three-year period. For this purpose, “stock” includes certain preferred stock. In the event of such an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our loss carryforwards that can be used to offset taxable income. The limitation is generally equal to the product of (a) the fair market value of our equity multiplied by (b) the long-term tax-exempt rate in effect for the month in which an ownership change occurs. In addition, if we are in a net unrealized built-in gain position at the time of an ownership change, then the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. If we are in a net unrealized built-in loss position at the time of an ownership change, then the limitation may apply to tax attributes other than just loss carryforwards, such as depreciable basis. Some states impose similar limitations on tax attribute utilization upon experiencing an ownership change. We do not believe we have a Section 382 limitation on the ability to utilize our U.S. loss carryforwards as of September 30, 2018.  Further, we do not expect an ownership change to occur as a result of the WildHorse Merger based on information known today.  However, issuances, sales and/or exchanges of our stock (including, potentially, relatively small transactions and transactions beyond our control) occurring after September 30, 2018, taken together with prior transactions with respect to our stock and the WildHorse Merger, could trigger an ownership change under Section 382 of the Code and therefore a limitation on our ability to utilize our U.S. loss carryforwards. Any such limitation could cause some of such loss carryforwards to expire before we would be able to utilize them to reduce taxable income in future periods, possibly resulting in a substantial income tax expense or write down of our tax assets or both.
ITEM 2.
Unregistered Sales of Equity Securities and Use of Proceeds
The following table presents information about repurchases of our common stock during the quarter ended September 30, 2018:
Period
 
Total
Number
of Shares
Purchased(a)
 
Average
Price
Paid
Per
Share(a)
 
Total Number
of Shares
Purchased as
Part of
Publicly
Announced
Plans or
Programs
 
Maximum
Approximate
Dollar Value
of Shares
That May Yet
Be Purchased
Under
the Plans
or Programs(b)
 
 
 
 
 
 
 
 
($ in millions)
July 1, 2018 through July 31, 2018
 
9,376

 
$
5.32

 
—

 
$
1,000

August 1, 2018 through August 31, 2018
 
—

 
$
—

 
—

 
$
1,000

September 1, 2018 through September 30, 2018
 
—

 
$
—

 
—

 
$
1,000

Total
 
9,376

 
$
—

 
—

 
 
___________________________________________
(a)
Includes shares of common stock purchased on behalf of our deferred compensation plan.
(b)
In December 2014, our Board of Directors authorized the repurchase of up to $1 billion of our common stock from time to time. The repurchase program does not have an expiration date. As of September 30, 2018, there have been no repurchases under the program.
ITEM 3.
Defaults Upon Senior Securities
None.
ITEM 4.
Mine Safety Disclosures
Not applicable.

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ITEM 5.
Other Information

Not applicable.


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ITEM 6.
Exhibits
The exhibits listed below in the Index of Exhibits are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.
INDEX OF EXHIBITS
 
 
 
 
Incorporated by Reference
 
 
Exhibit
Number
 
Exhibit Description
 
Form
 
SEC File
Number
 
Exhibit
 
Filing Date
 
Filed or
Furnished
Herewith
2.1
 
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
3.1.1
 
 
10-Q
 
001-13726
 
3.1.1
 
8/3/2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.1.2
 
 
10-Q
 
001-13726
 
3.1.4
 
11/10/2008
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.1.3
 
 
10-Q
 
001-13726
 
3.1.6
 
8/11/2008
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.1.4
 
 
8-K
 
001-13726
 
3.2
 
5/20/2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.1.5
 
 
10-Q
 
001-13726
 
3.1.5
 
8/9/2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.2
 
 
8-K
 
001-13726
 
3.2
 
6/19/2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.1
 

 
8-K
 
001-13726
 
4.1
 
4/29/2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.2
 

 
8-K
 
001-13726
 
4.2
 
9/27/2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.3
 
 
8-K
 
001-13726
 
4.3
 
9/27/2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.4
 
 
8-K
 
001-13726
 
4.4
 
9/27/2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.5
 
 
8-K
 
001-13726
 
4.5
 
9/27/2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10.1
 
 
8-K
 
001-13726
 
10.1
 
9/12/2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
31.1
 
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
31.2
 
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
32.1
 
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
32.2
 
 
 
 
 
 
 
 
 
 
X

68
TABLE OF CONTENTS

 
 
 
 
 
 
 
 
 
 
 
 
 
101 INS
 
XBRL Instance Document.
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
101 SCH
 
XBRL Taxonomy Extension Schema Document.
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
101 CAL
 
XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
101 DEF
 
XBRL Taxonomy Extension Definition Linkbase Document.
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
101 LAB
 
XBRL Taxonomy Extension Labels Linkbase Document.
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
101 PRE
 
XBRL Taxonomy Extension Presentation Linkbase Document.
 
 
 
 
 
 
 
 
 
X


69
TABLE OF CONTENTS

Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
CHESAPEAKE ENERGY CORPORATION
 
 
 
 
Date: October 30, 2018
By:
 
/s/ ROBERT D. LAWLER      
 
 
 
Robert D. Lawler
President and Chief Executive Officer
 
 
 
 
Date: October 30, 2018
By:
 
/s/ DOMENIC J. DELL’OSSO, JR.
 
 
 
Domenic J. Dell’Osso, Jr.
Executive Vice President and
Chief Financial Officer


70