Document


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: