10-Q 1 chk-20170331_10q.htm 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 March 31, 2017
or
[ ] 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES [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 [ ] (Do not check if a smaller reporting company) 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 April 24, 2017, there were 908,067,225 shares of our $0.01 par value common stock outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2017

| PART I. FINANCIAL INFORMATION | Page
Item 1. | Condensed Consolidated Financial Statements (Unaudited) |
| Condensed Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016 | 1
| Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2017 and 2016 | 3
| Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2017 and 2016 | 4
| Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016 | 5
| Condensed Consolidated Statements of Stockholders’ Equity for the Three Months Ended March 31, 2017 and 2016 | 7
| Notes to the Condensed Consolidated Financial Statements |
| Note 1. Basis of Presentation | 8
| Note 2. Earnings per Share | 10
| Note 3. Debt | 11
| Note 4. Contingencies and Commitments | 15
| Note 5. Other Liabilities | 17
| Note 6. Equity | 18
| Note 7. Share-Based Compensation | 19
| Note 8. Derivative and Hedging Activities | 22
| Note 9. Oil and Natural Gas Property Transactions | 28
| Note 10. Variable Interest Entities | 30
| Note 11. Impairments | 31
| Note 12. Income Taxes | 32
| Note 13. Fair Value Measurements | 32
| Note 14. Segment Information | 33
| Note 15. Recently Issued Accounting Standards | 34
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 35
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 51
Item 4. | Controls and Procedures | 55
PART II. OTHER INFORMATION
Item 1. | Legal Proceedings | 56
Item 1A. | Risk Factors | 57
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 58
Item 3. | Defaults Upon Senior Securities | 58
Item 4. | Mine Safety Disclosures | 58
Item 5. | Other Information | 58
Item 6. | Exhibits | 58

TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION

ITEM 1. | Condensed Consolidated Financial Statements (Unaudited)

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

|  | March 31, 2017 |  | December 31, 2016
|  | ($ in millions)
CURRENT ASSETS: |  |  |  |
Cash and cash equivalents ($1 and $1 attributable to our VIE) |  | $ | 249 |  |  | $ | 882 |
Accounts receivable, net |  | 943 |  |  | 1,057 |
Short-term derivative assets |  | 1 |  |  | — |
Other current assets |  | 167 |  |  | 203 |
Total Current Assets |  | 1,360 |  |  | 2,142 |
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) |  | 66,847 |  |  | 66,451 |
Unproved properties |  | 4,110 |  |  | 4,802 |
Other property and equipment |  | 2,045 |  |  | 2,053 |
Total Property and Equipment, at Cost |  | 73,002 |  |  | 73,306 |
Less: accumulated depreciation, depletion and amortization (($459) and ($458) attributable to our VIE) |  | (62,934 | ) |  | (62,726 | )
Property and equipment held for sale, net |  | 13 |  |  | 29 |
Total Property and Equipment, Net |  | 10,081 |  |  | 10,609 |
LONG-TERM ASSETS: |  |  |  |
Long-term derivative assets |  | 7 |  |  | — |
Other long-term assets |  | 251 |  |  | 277 |
TOTAL ASSETS |  | 11,699 |  |  | 13,028 |

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

|  | March 31, 2017 |  | December 31, 2016
|  | ($ in millions)
CURRENT LIABILITIES: |  |  |  |
Accounts payable |  | 678 |  |  | 672 |
Current maturities of long-term debt, net |  | 15 |  |  | 503 |
Accrued interest |  | 140 |  |  | 113 |
Short-term derivative liabilities |  | 157 |  |  | 562 |
Other current liabilities ($3 and $3 attributable to our VIE) |  | 1,798 |  |  | 1,798 |
Total Current Liabilities |  | 2,788 |  |  | 3,648 |
LONG-TERM LIABILITIES: |  |  |  |
Long-term debt, net |  | 9,509 |  |  | 9,938 |
Long-term derivative liabilities |  | 1 |  |  | 15 |
Asset retirement obligations, net of current portion |  | 236 |  |  | 247 |
Other long-term liabilities |  | 368 |  |  | 383 |
Total Long-Term Liabilities |  | 10,114 |  |  | 10,583 |
CONTINGENCIES AND COMMITMENTS (Note 4) |  |  |  |
EQUITY: |  |  |  |
Chesapeake Stockholders’ Equity: |  |  |  |
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 5,603,458 and 5,839,506 shares outstanding |  | 1,671 |  |  | 1,771 |
Common stock, $0.01 par value, 1,500,000,000 shares authorized: 908,042,914 and 896,279,353 shares issued |  | 9 |  |  | 9 |
Additional paid-in capital |  | 14,439 |  |  | 14,486 |
Accumulated deficit |  | (17,463 | ) |  | (17,603 | )
Accumulated other comprehensive loss |  | (82 | ) |  | (96 | )
Less: treasury stock, at cost; 2,368,008 and 1,220,504 common shares |  | (33 | ) |  | (27 | )
Total Chesapeake Stockholders’ Equity (Deficit) |  | (1,459 | ) |  | (1,460 | )
Noncontrolling interests |  | 256 |  |  | 257 |
Total Equity (Deficit) |  | (1,203 | ) |  | (1,203 | )
TOTAL LIABILITIES AND EQUITY |  | $ | 11,699 |  |  | $ | 13,028 |

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

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions except per share data)
REVENUES: |  |  |  |
Oil, natural gas and NGL |  | $ | 1,469 |  |  | $ | 993 |
Marketing, gathering and compression |  | 1,284 |  |  | 960 |
Total Revenues |  | 2,753 |  |  | 1,953 |
OPERATING EXPENSES: |  |  |  |
Oil, natural gas and NGL production |  | 135 |  |  | 206 |
Oil, natural gas and NGL gathering, processing and transportation |  | 355 |  |  | 482 |
Production taxes |  | 22 |  |  | 18 |
Marketing, gathering and compression |  | 1,328 |  |  | 942 |
General and administrative |  | 65 |  |  | 48 |
Provision for legal contingencies |  | (2 | ) |  | 33 |
Oil, natural gas and NGL depreciation, depletion and amortization |  | 197 |  |  | 263 |
Depreciation and amortization of other assets |  | 21 |  |  | 29 |
Impairment of oil and natural gas properties |  | — |  |  | 997 |
Impairments of fixed assets and other |  | 391 |  |  | 38 |
Net gains on sales of fixed assets |  | — |  |  | (4 | )
Total Operating Expenses |  | 2,512 |  |  | 3,052 |
INCOME (LOSS) FROM OPERATIONS |  | 241 |  |  | (1,099 | )
OTHER INCOME (EXPENSE): |  |  |  |
Interest expense |  | (95 | ) |  | (62 | )
Loss on sale of investment |  | — |  |  | (10 | )
Gains (losses) on purchases or exchanges of debt |  | (7 | ) |  | 100 |
Other income |  | 3 |  |  | 3 |
Total Other Income (Expense) |  | (99 | ) |  | 31 |
INCOME (LOSS) BEFORE INCOME TAXES |  | 142 |  |  | (1,068 | )
Income Tax Expense |  | 1 |  |  | — |
NET INCOME (LOSS) |  | 141 |  |  | (1,068 | )
Net income attributable to noncontrolling interests |  | (1 | ) |  | — |
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE |  | 140 |  |  | (1,068 | )
Preferred stock dividends |  | (23 | ) |  | (43 | )
Loss on exchange of preferred stock |  | (41 | ) |  | — |
Earnings allocated to participating securities |  | (1 | ) |  | — |
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS |  | $ | 75 |  |  | $ | (1,111 | )
EARNINGS (LOSS) PER COMMON SHARE: |  |  |  |
Basic |  | $ | 0.08 |  |  | $ | (1.66 | )
Diluted |  | $ | 0.08 |  |  | $ | (1.66 | )
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions): |  |  |  |
Basic |  | 906 |  |  | 668 |
Diluted |  | 907 |  |  | 668 |

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

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
NET INCOME (LOSS) |  | $ | 141 |  |  | $ | (1,068 | )
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX: |  |  |  |
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of $0 and ($3) |  | 4 |  |  | (4 | )
Reclassification of losses on settled derivative instruments, net of income tax expense (benefit) of $0 and $7 |  | 10 |  |  | 4 |
Other Comprehensive Income (Loss) |  | 14 |  |  | — |
COMPREHENSIVE INCOME (LOSS) |  | 155 |  |  | (1,068 | )
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS |  | (1 | ) |  | — |
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE |  | $ | 154 |  |  | $ | (1,068 | )

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

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES: |  |  |  |
NET INCOME (LOSS) |  | $ | 141 |  |  | $ | (1,068 | )
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES: |  |  |  |
Depreciation, depletion and amortization |  | 218 |  |  | 292 |
Derivative gains, net |  | (322 | ) |  | (201 | )
Cash receipts (payments) on derivative settlements, net |  | (34 | ) |  | 267 |
Stock-based compensation |  | 11 |  |  | 12 |
Impairment of oil and natural gas properties |  | — |  |  | 997 |
Net gains on sales of fixed assets |  | — |  |  | (4 | )
Impairments of fixed assets and other |  | (3 | ) |  | 33 |
Loss on sale of investment |  | — |  |  | 10 |
(Gains) losses on purchases or exchanges of debt |  | 6 |  |  | (100 | )
Provision for legal contingencies |  | (2 | ) |  | 33 |
Other |  | (29 | ) |  | (8 | )
Changes in assets and liabilities |  | 113 |  |  | (684 | )
Net Cash Provided By (Used In) Operating Activities |  | 99 |  |  | (421 | )
CASH FLOWS FROM INVESTING ACTIVITIES: |  |  |  |
Drilling and completion costs |  | (433 | ) |  | (265 | )
Acquisitions of proved and unproved properties |  | (95 | ) |  | (67 | )
Proceeds from divestitures of proved and unproved properties |  | 892 |  |  | 62 |
Additions to other property and equipment |  | (3 | ) |  | (10 | )
Proceeds from sales of other property and equipment |  | 19 |  |  | 9 |
Other |  | — |  |  | (2 | )
Net Cash Provided By (Used In) Investing Activities |  | 380 |  |  | (273 | )
CASH FLOWS FROM FINANCING ACTIVITIES: |  |  |  |
Cash paid to purchase debt |  | (982 | ) |  | (472 | )
Proceeds from revolving credit facility borrowings |  | 50 |  |  | 515 |
Payments on revolving credit facility borrowings |  | (50 | ) |  | (148 | )
Cash paid for preferred stock dividends |  | (114 | ) |  | — |
Distributions to noncontrolling interest owners |  | (2 | ) |  | (5 | )
Other |  | (14 | ) |  | (5 | )
Net Cash Used In Financing Activities |  | (1,112 | ) |  | (115 | )
Net decrease in cash and cash equivalents |  | (633 | ) |  | (809 | )
Cash and cash equivalents, beginning of period |  | 882 |  |  | 825 |
Cash and cash equivalents, end of period |  | $ | 249 |  |  | $ | 16 |

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

Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
SUPPLEMENTAL CASH FLOW INFORMATION: |  |  |  |
Interest paid, net of capitalized interest |  | $ | 92 |  |  | $ | 39 |
Income taxes paid, net of refunds received |  | $ | 1 |  |  | $ | (19 | )
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES: |  |  |  |
Change in accrued drilling and completion costs |  | $ | 68 |  |  | $ | (9 | )
Change in accrued acquisitions of proved and unproved properties |  | $ | 8 |  |  | $ | — |
Change in divested proved and unproved properties |  | $ | (8 | ) |  | $ | — |
Debt exchanged for common stock |  | $ | — |  |  | $ | 77 |

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

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
PREFERRED STOCK: |  |  |  |
Balance, beginning of period |  | $ | 1,771 |  |  | $ | 3,062 |
Exchange/conversions of 236,048 and 25,802 shares of preferred stock for common stock |  | (100 | ) |  | (26 | )
Balance, end of period |  | 1,671 |  |  | 3,036 |
COMMON STOCK: |  |  |  |
Balance, beginning and end of period |  | 9 |  |  | 7 |
ADDITIONAL PAID-IN CAPITAL: |  |  |  |
Balance, beginning of period |  | 14,486 |  |  | 12,403 |
Stock-based compensation |  | 10 |  |  | 16 |
Exchange of contingent convertible notes for 0 and 14,699,368 shares of common stock |  | — |  |  | 65 |
Exchange of senior notes for 0 and 2,555,979 shares of common stock |  | — |  |  | 11 |
Exchange/conversion of preferred stock for 9,965,835 and 1,021,506 shares of common stock |  | 100 |  |  | 26 |
Equity component of contingent convertible notes repurchased |  | (20 | ) |  | — |
Dividends on preferred stock |  | (137 | ) |  | — |
Balance, end of period |  | 14,439 |  |  | 12,521 |
RETAINED EARNINGS (ACCUMULATED DEFICIT): |  |  |  |
Balance, beginning of period |  | (17,603 | ) |  | (13,202 | )
Net income (loss) attributable to Chesapeake |  | 140 |  |  | (1,068 | )
Balance, end of period |  | (17,463 | ) |  | (14,270 | )
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS): |  |  |  |
Balance, beginning of period |  | (96 | ) |  | (99 | )
Hedging activity |  | 14 |  |  | — |
Balance, end of period |  | (82 | ) |  | (99 | )
TREASURY STOCK – COMMON: |  |  |  |
Balance, beginning of period |  | (27 | ) |  | (33 | )
Purchase of 1,185,517 and 10,100 shares for company benefit plans |  | (7 | ) |  | — |
Release of 38,013 and 63,318 shares from company benefit plans |  | 1 |  |  | 2 |
Balance, end of period |  | (33 | ) |  | (31 | )
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT) |  | (1,459 | ) |  | 1,164 |
NONCONTROLLING INTERESTS: |  |  |  |
Balance, beginning of period |  | 257 |  |  | 259 |
Net income attributable to noncontrolling interests |  | 1 |  |  | — |
Distributions to noncontrolling interest owners |  | (2 | ) |  | 1 |
Balance, end of period |  | 256 |  |  | 260 |
TOTAL EQUITY (DEFICIT) |  | $ | (1,203 | ) |  | $ | 1,424 |

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 Energy Corporation (“Chesapeake” or the “Company”) were prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated. These financial statements were prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP.
This Form 10-Q relates to the three months ended March 31, 2017 (the “Current Quarter”) and the three months ended March 31, 2016 (the “Prior Quarter”). Chesapeake’s annual report on Form 10-K for the year ended December 31, 2016 (“2016 Form 10-K”) includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair statement of the results for the interim periods have been reflected. The results for the Current Quarter are not necessarily indicative of the results to be expected for the full year.
Risks and Uncertainties
Our ability to grow, make capital expenditures and service our debt depends primarily upon the prices we receive for the oil, natural gas and natural gas liquids (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 very volatile, and may be subject to wide fluctuations in the future. The substantial decline in oil, natural gas and NGL prices from 2014 levels has negatively affected the amount of liquidity we have available for capital expenditures and debt service. A substantial or extended decline in oil, natural gas and NGL prices could have a material impact on our financial position, results of operations, cash flows and on the quantities of reserves that we may economically produce. Other risks and uncertainties that could affect us in a low commodity price environment include, but are not limited to, counterparty credit risk for our receivables, access to capital markets, regulatory risks and our ability to meet financial ratios and covenants in our financing agreements.
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Revision of Prior Quarter
During the fourth quarter of 2016, we identified certain errors to the basis price differentials used in calculating the impairment of oil and natural gas properties and oil, natural gas and NGL depreciation, depletion and amortization for each of the first three interim periods in 2016. As disclosed within our 2016 Form 10-K, it was determined that these errors were not material to our previously issued 2016 interim financial statements. Accordingly, the correction of these errors and another immaterial previously identified error was reflected in the quarterly unaudited financial data included within our 2016 Form 10-K. These revisions have been reflected in the comparative 2016 condensed consolidated financi al statements presented herein. See Evaluation of Disclosure Controls and Procedure s in Item 4 of this Form 10-Q. The following table reconciles the amounts as previously reported in the applicable financial statement to the corresponding revised amounts:

|  | Three Months Ended March 31, 2016
|  | As Previously Reported |  | Revision Adjustment |  | As Revised
|  | ($ in millions)
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS |  |  |  |  |  |
Provision for legal contingencies |  | $ | 22 |  |  | $ | 11 |  |  | $ | 33 |
Oil, natural gas and NGL depreciation, depletion and amortization |  | $ | 271 |  |  | $ | (8 | ) |  | $ | 263 |
Impairment of oil and natural gas properties |  | $ | 853 |  |  | $ | 144 |  |  | $ | 997 |
Total operating expenses |  | $ | 2,905 |  |  | $ | 147 |  |  | $ | 3,052 |
Loss from operations |  | $ | (952 | ) |  | $ | (147 | ) |  | $ | (1,099 | )
Loss before income taxes |  | $ | (921 | ) |  | $ | (147 | ) |  | $ | (1,068 | )
Net loss |  | $ | (921 | ) |  | $ | (147 | ) |  | $ | (1,068 | )
Net loss attributable to Chesapeake |  | $ | (921 | ) |  | $ | (147 | ) |  | $ | (1,068 | )
Net loss available to common stockholders |  | $ | (964 | ) |  | $ | (147 | ) |  | $ | (1,111 | )
Earnings (loss) per common share basic |  | $ | (1.44 | ) |  | $ | (0.22 | ) |  | $ | (1.66 | )
Earnings (loss) per common share diluted |  | $ | (1.44 | ) |  | $ | (0.22 | ) |  | $ | (1.66 | )

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) |  |  |  |  |  |
Net loss |  | $ | (921 | ) |  | $ | (147 | ) |  | $ | (1,068 | )
Comprehensive loss |  | $ | (921 | ) |  | $ | (147 | ) |  | $ | (1,068 | )
Comprehensive loss attributable to Chesapeake |  | $ | (921 | ) |  | $ | (147 | ) |  | $ | (1,068 | )

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS |  |  |  |  |  |
Net loss |  | $ | (921 | ) |  | $ | (147 | ) |  | $ | (1,068 | )
Depreciation, depletion and amortization |  | $ | 300 |  |  | $ | (8 | ) |  | $ | 292 |
Impairment of oil and natural gas properties |  | $ | 853 |  |  | $ | 144 |  |  | $ | 997 |
Provision for legal contingencies |  | $ | 22 |  |  | $ | 11 |  |  | $ | 33 |
Net cash used in operating activities |  | $ | (421 | ) |  | $ | — |  |  | $ | (421 | )

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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 the Current Quarter and the Prior Quarter, 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.
For the Current Quarter and the Prior Quarter, shares of common stock for the following dilutive securities were excluded from the calculation of diluted EPS as the effect was antidilutive.

|  | Shares
|  | (in millions)
Three Months Ended March 31, 2017 |  |
Common stock equivalent of our preferred stock outstanding: |  |
5.75% cumulative convertible preferred stock |  | 31 |
5.75% cumulative convertible preferred stock (series A) |  | 18 |
5.00% cumulative convertible preferred stock (series 2005B) |  | 5 |
4.50% cumulative convertible preferred stock |  | 6 |
Participating securities |  | 1 |
Common stock equivalent of our convertible senior notes outstanding: |  |
5.5% convertible senior notes |  | 146 |
Common stock equivalent of our preferred stock outstanding prior to exchange: |  |
5.75% cumulative convertible preferred stock exchanged |  | 1 |
5.75% cumulative convertible preferred stock (series A) exchanged |  | — |
5.00% cumulative convertible preferred stock (series 2005B) exchanged |  | — |
Three Months Ended March 31, 2016 |  |
Common stock equivalent of our preferred stock outstanding: |  |
5.75% cumulative convertible preferred stock |  | 58 |
5.75% cumulative convertible preferred stock (series A) |  | 42 |
5.00% cumulative convertible preferred stock (series 2005B) |  | 6 |
4.50% cumulative convertible preferred stock |  | 6 |
Participating securities |  | 1 |

For the Current Quarter, outstanding stock options were included in the calculation of diluted EPS. A reconciliation of basic EPS and diluted EPS for the Current Quarter is as follows:

|  | Income (Numerator) |  | Weighted Average Shares (Denominator) |  | Per Share Amount
|  | (in millions, except per share data)
Three Months Ended March 31, 2017 |  |  |  |  |  |
Basic EPS |  | $ | 75 |  |  | 906 |  |  | $ | 0.08 |
Effect of Dilutive Securities: |  |  |  |  |  |
Outstanding stock options |  | — |  |  | 1 |  |  |
Diluted EPS |  | $ | 75 |  |  | 907 |  |  | $ | 0.08 |

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

3. | Debt

Our long-term debt consisted of the following as of March 31, 2017 and December 31, 2016:

|  | March 31, 2017 |  | December 31, 2016
|  | Principal Amount |  | Carrying Amount |  | Principal Amount |  | Carrying Amount
|  | ($ in millions)
Term loan due 2021 |  | $ | 1,500 |  |  | $ | 1,500 |  |  | $ | 1,500 |  |  | $ | 1,500 |
6.25% euro-denominated senior notes due 2017(a) |  | — |  |  | — |  |  | 258 |  |  | 258 |
6.5% senior notes due 2017 |  | — |  |  | — |  |  | 134 |  |  | 134 |
7.25% senior notes due 2018 |  | 46 |  |  | 46 |  |  | 64 |  |  | 64 |
Floating rate senior notes due 2019 |  | 380 |  |  | 380 |  |  | 380 |  |  | 380 |
6.625% senior notes due 2020 |  | 572 |  |  | 572 |  |  | 780 |  |  | 780 |
6.875% senior notes due 2020 |  | 279 |  |  | 279 |  |  | 279 |  |  | 279 |
6.125% senior notes due 2021 |  | 550 |  |  | 550 |  |  | 550 |  |  | 550 |
5.375% senior notes due 2021 |  | 270 |  |  | 270 |  |  | 270 |  |  | 270 |
4.875% senior notes due 2022 |  | 451 |  |  | 451 |  |  | 451 |  |  | 451 |
8.00% senior secured second lien notes due 2022(b) |  | 2,419 |  |  | 3,368 |  |  | 2,419 |  |  | 3,409 |
5.75% senior notes due 2023 |  | 338 |  |  | 338 |  |  | 338 |  |  | 338 |
8.00% senior notes due 2025 |  | 1,000 |  |  | 1,000 |  |  | 1,000 |  |  | 1,000 |
5.5% convertible senior notes due 2026(c)(e) |  | 1,250 |  |  | 818 |  |  | 1,250 |  |  | 811 |
2.75% contingent convertible senior notes due 2035(d) |  | 2 |  |  | 2 |  |  | 2 |  |  | 2 |
2.5% contingent convertible senior notes due 2037(d)(e) |  | 15 |  |  | 15 |  |  | 114 |  |  | 112 |
2.25% contingent convertible senior notes due 2038(d)(e) |  | 9 |  |  | 8 |  |  | 200 |  |  | 180 |
Revolving credit facility |  | — |  |  | — |  |  | — |  |  | — |
Debt issuance costs |  | — |  |  | (60 | ) |  | — |  |  | (64 | )
Discount on senior notes |  | — |  |  | (16 | ) |  | — |  |  | (16 | )
Interest rate derivatives(f) |  | — |  |  | 3 |  |  | — |  |  | 3 |
Total debt, net |  | 9,081 |  |  | 9,524 |  |  | 9,989 |  |  | 10,441 |
Less current maturities of long-term debt, net(g) |  | (15 | ) |  | (15 | ) |  | (506 | ) |  | (503 | )
Total long-term debt, net |  | $ | 9,066 |  |  | $ | 9,509 |  |  | $ | 9,483 |  |  | $ | 9,938 |

___________________________________________

(a) | The principal and carrying amounts shown are based on the exchange rate of $1.0517 to €1.00 as of December 31, 2016. See Foreign Currency Derivatives in Note 8 for information on our related foreign currency derivatives.

(b) | The carrying amounts as of March 31, 2017 and December 31, 2016, include premium amounts of $949 million and $990 million, respectively, associated with a troubled debt restructuring. The premium is being amortized based on the effective yield method.

(c) | The conversion and redemption provisions of our convertible senior notes are as follows:

Optional Conversion by Holders. Prior to maturity under certain circumstances and at the holder’s option, the notes are convertible into cash, our common stock, or a combination of cash and common stock, at our election. One triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the first quarter of 2017, the price of our common stock was below the threshold level and, as a result, the holders
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
do not have the option to convert their notes in the second quarter of 2017 under this provision. The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision during the Current Quarter. Upon conversion of a convertible senior note, the holder will receive cash, common stock or a combination of cash and common stock, at our election, according to the conversion rate specified in the indenture.
The common stock price conversion threshold amount for the convertible senior notes is 130% of the conversion price.
Optional Redemption by the Company. We may redeem the convertible senior notes for cash on or after September 15, 2019, if the price of our common stock exceeds 130% of the conversion price during a specified period at a redemption price of 100% of the principal amount of the notes.
Holders’ Demand Repurchase Rights. The holders of our convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes upon certain fundamental changes.

(d) | The repurchase, conversion, contingent interest and redemption provisions of our contingent convertible senior notes are as follows:

Holders’ Demand Repurchase Rights. The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date and upon certain fundamental changes.
Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, the notes are convertible into cash and, if applicable, our common stock using a net share settlement process. One triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period within a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the specified period in the Current Quarter, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash or common stock in the second quarter of 2017 under this provision.
The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision during the Current Quarter and the Prior Quarter. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note’s conversion value in excess of the principal amount.
Contingent Interest. We will pay contingent interest on the contingent convertible senior notes after they have been outstanding at least ten years during certain periods if the average trading price of the notes exceeds the threshold defined in the indenture.
The holders’ demand repurchase dates, the common stock price conversion threshold amounts (as adjusted to give effect to cash dividends on our common stock) and the ending date of the first six-month period in which contingent interest may be payable for the contingent convertible senior notes are as follows:

Contingent Convertible Senior Notes |  | Holders' Demand Repurchase Dates |  | Common Stock Price Conversion Thresholds |  | Contingent Interest First Payable (if applicable)
2.75% due 2035 |  | November 15, 2020, 2025, 2030 |  | $ | 45.02 |  |  | May 14, 2016
2.5% due 2037 |  | May 15, 2017, 2022, 2027, 2032 |  | $ | 59.44 |  |  | November 14, 2017
2.25% due 2038 |  | December 15, 2018, 2023, 2028, 2033 |  | $ | 100.20 |  |  | June 14, 2019

Optional Redemption by the Company. We may redeem the contingent convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash. In addition, we may redeem our 2.75% Contingent Convertible Senior Notes due 2035 at any time.
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(Unaudited)

(e) | The carrying amounts as of March 31, 2017 and December 31, 2016, are reflected net of discounts of $433 million and $461 million, respectively, associated with the equity component of our convertible and contingent convertible senior notes. This amount is being amortized based on the effective yield method through the first demand repurchase date as applicable.

(f) | See Interest Rate Derivatives in Note 8 for further discussion related to these instruments.

(g) | As of March 31, 2017, current maturities of long-term debt, net includes our 2.5% Contingent Convertible Senior Notes due 2037 (2037 Notes). As discussed in footnote (d) above, the holders of our 2037 Notes could exercise their individual demand repurchase rights on May 15, 2017, which would require us to repurchase all or a portion of the principal amount of the notes.

Term Loan Facility
We have a secured five-year term loan facility in aggregate principal amount of $1.5 billion. Our obligations under the facility are unconditionally guaranteed on a joint and several basis by the same subsidiaries that guarantee our revolving credit facility, second lien notes and senior notes and are secured by first-priority liens on the same collateral securing our revolving credit facility (with a position in the collateral proceeds waterfall junior to the revolving credit facility). The term loan bears interest at a rate of London Interbank Offered Rate (LIBOR) plus 7.50% per annum, subject to a 1.00% LIBOR floor, or the Alternative Base Rate (ABR) plus 6.50% per annum, subject to a 2.00% ABR floor, at our option. The term loan matures in August 2021 and voluntary prepayments are subject to a make-whole premium prior to the second anniversary of the closing of the term loan, a premium to par of 4.25% from the second anniversary until but excluding the third anniversary, a premium to par of 2.125% from the third anniversary until but excluding the fourth anniversary and at par beginning on the fourth anniversary. The term loan may be subject to mandatory prepayments and offers to purchase with net cash proceeds of certain issuances of debt, certain asset sales and other dispositions of collateral and upon a change of control.
Senior Secured Second Lien Notes
Our second lien notes are secured second lien obligations and are effectively junior to our current and future secured first lien indebtedness, including indebtedness incurred under our revolving credit facility and our term loan facility, to the extent of the value of the collateral securing such indebtedness, effectively senior to all of our existing and future unsecured indebtedness, including our outstanding senior notes, to the extent of the value of the collateral, and senior to any future subordinated indebtedness that we may incur. We have the option to redeem the second lien notes, in whole or in part, at specified make-whole or redemption prices. Our second lien notes are governed by an indenture containing covenants that may limit our ability and our subsidiaries’ ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, consolidate, merge or transfer assets and dispose of certain collateral and use proceeds from dispositions of certain collateral. As a holding company, Chesapeake owns no operating assets and has no significant operations independent of its subsidiaries. Chesapeake’s obligations under the second lien notes are fully and unconditionally guaranteed, jointly and severally, by certain of our direct and indirect wholly owned subsidiaries.
In December 2015, certain of the existing notes that were exchanged for the second lien notes were accounted for as a troubled debt restructuring (TDR). For the exchanges classified as a TDR, if the future undiscounted cash flows of the newly issued debt are less than the net carrying value of the original debt, a gain is recorded for the difference and the carrying value of the newly issued debt is adjusted to the future undiscounted cash flow amount and no future interest expense is recorded. All future interest payments on the newly issued debt reduce the carrying value.
Senior Notes, Contingent Convertible Senior Notes and Convertible Senior Notes
Chesapeake Energy Corporation is a holding company and has no independent assets or operations. Our obligations under our outstanding senior notes and convertible senior notes are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Our non-guarantor subsidiaries are minor and, as such, we have not included condensed consolidating financial information in the notes to our condensed consolidated financial statements.
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(Unaudited)
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 2.5% Contingent Convertible Senior Notes due 2037, our 2.25% Contingent Convertible Senior Notes due 2038 and our 5.5% Convertible Senior Notes due 2026 are 8.0%, 8.0% and 11.5%, respectively.
In the Current Quarter, we retired $908 million principal amount of our outstanding senior notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $982 million. Included in these retirements is the maturity of our 6.25% Euro-denominated Senior Notes due 2017, which were carried at $258 million based on the December 31, 2016 exchange rate of $1.0517 to €1.00 and the corresponding cross currency swap. See Foreign Currency Derivatives in Note 8 for further information. For the open market repurchases and tender offers, we recorded an aggregate loss of approximately $7 million.
In the Prior Quarter, we retired $558 million principal amount of our outstanding senior notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $472 million. Additionally, we privately negotiated an exchange of approximately $105 million principal amount of our outstanding senior notes and contingent convertible senior notes for 17,255,347 common shares. We recorded an aggregate gain of approximately $100 million associated with these repurchases and exchanges.
Revolving Credit Facility
We have a $4.0 billion senior secured revolving credit facility that matures in December 2019. As of March 31, 2017, we had no outstanding borrowings under the revolving credit facility and had used $697 million of the revolving credit facility for various letters of credit (including the $461 million supersedeas bond with respect to the 2019 Notes litigation discussed in Note 4). As discussed in Note 4, on April 28, 2017, the Company paid $441 million as a result of the 2019 Notes litigation with cash on hand and borrowings under the revolving credit facility and the related supersedeas bond was released. The terms of the revolving credit facility include covenants limiting, among other things, our ability to incur additional indebtedness, make investments or loans, create liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates. We were in compliance with all applicable financial covenants under the agreement as of March 31, 2017.
During 2016, we entered into the third amendment to our revolving credit facility. Pursuant to the amendment, our borrowing base was reaffirmed in the amount of $4.0 billion and the next scheduled borrowing base redetermination review was postponed until June 15, 2017, with the consenting lenders agreeing not to exercise their interim redetermination right prior to that date. As a result of certain asset sales and certain other sales of collateral since the date of the most recent amendment, our borrowing base was reduced to $3.8 billion in the fourth quarter of 2016. Our borrowing base may be further reduced if we dispose of a certain percentage of the value of collateral securing the facility. The amendment also granted temporary financial covenant relief, with the revolving credit facility’s existing first lien secured leverage ratio and net debt to capitalization ratio suspended until September 30, 2017 and the interest coverage ratio maintenance covenant reduced as noted below. In addition, we agreed to grant liens and security interests on a majority of our assets, as well as maintain a minimum liquidity amount (defined as cash and cash equivalents and availability under our revolving credit facility) of $500 million until the suspension of the existing maintenance covenants ends.
The amendment reduced the interest coverage ratio from 1.1 to 1.0 to 0.65 to 1.0 through the first quarter of 2017, after which it will increase to 0.70 to 1.0 for the second quarter of 2017, 1.2 to 1.0 for the third quarter of 2017 and 1.25 to 1.0 thereafter. The amendment also includes a collateral value coverage test whereby if the collateral value coverage ratio, tested as of March 31, 2017, falls below 1.25 to 1.0, our borrowing ability will be reduced in order to satisfy such ratio. Our collateral value exceeded the 1.25 to 1.0 threshold as of March 31, 2017. The amendment also gives us the ability to incur up to $2.5 billion of first lien indebtedness secured on a pari passu basis with the existing obligations under the credit agreement, subject to a position in the collateral proceeds waterfall in favor of the revolving lenders and affiliated hedge providers and the other limitations on junior lien debt set forth in the credit agreement. After taking into account the term loan, the amount of additional first lien indebtedness permitted by the revolving credit facility is $1.0 billion.
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(Unaudited)
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.

|  | March 31, 2017 |  | December 31, 2016
|  | Carrying Amount |  | Estimated Fair Value |  | Carrying Amount |  | Estimated Fair Value
|  |  |  | ($ in millions) |  |
Short-term debt (Level 1) |  | $ | 15 |  |  | $ | 15 |  |  | $ | 503 |  |  | $ | 511 |
Long-term debt (Level 1) |  | $ | 2,877 |  |  | $ | 2,785 |  |  | $ | 3,271 |  |  | $ | 3,216 |
Long-term debt (Level 2) |  | $ | 6,629 |  |  | $ | 6,421 |  |  | $ | 6,664 |  |  | $ | 6,654 |

4. | Contingencies and Commitments

Contingencies
Litigation and Regulatory Proceedings
The Company is involved in a number of litigation and regulatory proceedings (including those described below). Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. We estimate and provide for potential losses that may arise out of litigation and regulatory proceedings to the extent that such losses are probable and can be reasonably estimated. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different. Our total estimated liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. We account for legal defense costs in the period the costs are incurred.
Regulatory and Related Proceedings. The Company has received, from the U.S. Department of Justice (DOJ) and certain state governmental agencies and authorities, subpoenas and demands for documents, information and testimony in connection with investigations into possible violations of federal and state antitrust laws relating to our purchase and lease of oil and natural gas rights in various states. The Company also has received DOJ, U.S. Postal Service and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake has engaged in discussions with the DOJ, U.S. Postal Service and state agency representatives and continues to respond to such subpoenas and demands.
In addition, the Company received a DOJ subpoena and a voluntary document request from the SEC seeking information on our accounting methodology for the acquisition and classification of oil and natural gas properties and related matters. Chesapeake has engaged in discussions with the DOJ and SEC about these matters. On October 4, 2016, a securities class action was filed in the U.S. District Court for the Western District of Oklahoma against the Company and certain current directors and officers of the Company alleging, among other things, violations of federal securities laws for purported misstatements in the Company’s SEC filings and other public disclosures regarding the Company’s accounting for the acquisition and classification of oil and natural gas properties. The lawsuit seeks certification as a class action, damages, attorneys’ fees and other costs.
Redemption of 2019 Notes. As previously disclosed in the 2015 Form 10-K, in connection with the litigation related to the Company’s notice issued on March 15, 2013 to redeem all of the 2019 Notes at par (plus accrued interest through the redemption date) pursuant to the special early redemption provision of the supplemental indenture governing the 2019 Notes, the Company filed a notice of appeal on July 27, 2015, of an amended judgment entered on July 17, 2015, by the U.S. District Court for the Southern District of New York awarding the Trustee for the 2019 Notes $380 million plus prejudgment interest in the amount of $59 million. The Company posted a supersedeas bond in the amount of $461 million (reflected as an outstanding letter of credit under the Company’s revolving credit facility) to stay execution of the judgment while appellate proceedings are pending. The Company accrued a loss contingency of $100 million for this matter in 2014 and an additional $339 million in 2015. On September 15, 2016, the U.S. Court of Appeals for the Second Circuit affirmed the trial court’s ruling. On April 24, 2017, the U.S. Supreme Court denied the Company’s petition for writ of certiorari seeking review of the Court of Appeals’ decision. As a result of this decision, we paid the judgment on April 28, 2017 and the related supersedeas bond was released.
Business Operations. Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL. Plaintiffs have varying royalty provisions in their respective leases, oil and gas law varies from state to state, and royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations. The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defending lawsuits seeking damages with respect to royalty underpayment in various states, including, but not limited to, Texas, Pennsylvania, Ohio, Oklahoma, Kentucky, Louisiana and Arkansas. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The Company also has received DOJ, U.S. Postal Service and state subpoenas or information requests seeking information on the Company’s royalty payment practices.
Chesapeake is defending numerous lawsuits filed by individual royalty owners alleging royalty underpayment with respect to properties in Texas. These lawsuits, organized for pre-trial proceedings with respect to the Barnett Shale and Eagle Ford Shale, respectively, generally allege that Chesapeake underpaid royalties by making improper deductions, using incorrect production volumes and similar theories. Chesapeake expects that additional lawsuits will continue to be pursued and that new plaintiffs will file other lawsuits making similar allegations.
On December 9, 2015, the Commonwealth of Pennsylvania, by the Office of Attorney General, filed a lawsuit in the Bradford County Court of Common Pleas related to royalty underpayment and lease acquisition and accounting practices with respect to properties in Pennsylvania. The lawsuit, which primarily relates to the Marcellus Shale and Utica Shale, alleges that Chesapeake violated the Pennsylvania Unfair Trade Practices and Consumer Protection Law (UTPCPL) by making improper deductions and entering into arrangements with affiliates that resulted in underpayment of royalties. The lawsuit includes other UTPCPL claims and antitrust claims, including that a joint exploration agreement to which Chesapeake is a party established unlawful market allocation for the acquisition of leases. The lawsuit seeks statutory restitution, civil penalties and costs, as well as temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid and permanent injunction from further violations of the UTPCPL. Chesapeake has filed preliminary objections to the most recently amended complaint.
Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the Company’s divestiture of substantially all of its midstream business and most of its gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and for an unlawful market allocation agreement for mineral rights. One of the cases includes claims of intentional interference with contractual relations and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources.
We believe losses are reasonably possible in certain of the pending royalty cases for which we have not accrued a loss contingency, but we are currently unable to estimate an amount or range of loss or the impact the actions could have on our future results of operations or cash flows. Uncertainties in pending royalty cases generally include the complex nature of the claims and defenses, the potential size of the class in class actions, the scope and types of the properties and agreements involved, and the applicable production years.
The Company is also 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 the Company 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.
Other Matters
Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to the Company’s business operations is likely to have a material adverse effect on its future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
Environmental Contingencies
The nature of the oil and gas business carries with it certain environmental risks for Chesapeake and its subsidiaries. Chesapeake has implemented various policies, programs, procedures, training and auditing to reduce and mitigate such environmental risks. Chesapeake conducts periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, Chesapeake may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.
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 condensed 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.

|  | March 31, 2017
|  | ($ in millions)
2017 |  | $ | 977 |
2018 |  | 1,102 |
2019 |  | 1,067 |
2020 |  | 989 |
2021 |  | 894 |
2022 – 2035 |  | 5,212 |
Total |  | $ | 10,241 |

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 vary with the applicable agreement.
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(Unaudited)
Drilling Contracts
We have contracts with various drilling contractors to utilize drilling services at market-based pricing. These commitments are not recorded as obligations in the accompanying condensed consolidated balance sheets. As of March 31, 2017, the aggregate undiscounted minimum future payments under these drilling service commitments were approximately $75 million.
Pressure Pumping Contracts
We have an agreement for pressure pumping services, which expires in June 2017. The services agreement requires us to utilize, at market-based pricing, the lesser of (i) three pressure pumping crews through June 30, 2017, or (ii) 50% of the total number of all pressure pumping crews working for us in all of our operating regions during the respective year. We are also required to utilize the pressure pumping services for a minimum number of fracture stages as set forth in the agreement. We are entitled to terminate the agreement in certain situations, including if the contractor fails to provide the overall quality of service provided by similar service providers. These commitments are not recorded as obligations in the accompanying condensed consolidated balance sheets. As of March 31, 2017, the aggregate undiscounted minimum future payments under this agreement were approximately $26 million.
Oil, Natural Gas and NGL Purchase Commitments
We commit to purchase oil, natural gas and NGL from other owners in the properties we operate, including owners associated with our volumetric production payment (VPP) transactions. Production purchases under these arrangements are based on market prices at the time of production, and the purchased oil, natural gas and NGL are resold at market prices. See Volumetric Production Payments in Note 9 for further discussion of our VPP transactions.
Net Acreage Maintenance Commitments
Under the terms of our Utica Shale joint venture agreements with Total S.A., we are obligated to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage maintenance level is met as of the December 31, 2017 measurement date.
Other Commitments
As part of our normal course of business, we enter into various agreements providing, or otherwise arranging for, financial or performance assurances to third parties on behalf of our wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance.
In connection with acquisitions and divestitures, our purchase and sale agreements generally provide indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party and/or other specified matters. These indemnifications generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or cannot be quantified at the time of entering into or consummating a particular transaction. For divestitures of oil and natural gas properties, our purchase and sale agreements may require the return of a portion of the proceeds we receive as a result of uncured title defects.
Certain of our oil and natural gas properties are burdened by non-operating interests such as royalty and overriding royalty interests, including overriding royalty interests sold through our VPP transactions. As the holder of the working interest from which these interests have been created, we have the responsibility to bear the cost of developing and producing the reserves attributable to these interests. See Volumetric Production Payments in Note 9 for further discussion of our VPP transactions.
While executing our strategic priorities, we have incurred certain cash charges, including contract termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. As we continue to focus on our strategic priorities, we may take certain actions that reduce financial leverage and complexity, and we may incur additional cash and noncash charges.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

5. | Other Liabilities

Other current liabilities as of March 31, 2017 and December 31, 2016 are detailed below.

|  | March 31, 2017 |  | December 31, 2016
|  | ($ in millions)
Revenues and royalties due others |  | $ | 526 |  |  | $ | 543 |
Accrued drilling and production costs |  | 259 |  |  | 169 |
Joint interest prepayments received |  | 76 |  |  | 71 |
Accrued compensation and benefits |  | 137 |  |  | 239 |
Other accrued taxes |  | 37 |  |  | 32 |
Bank of New York Mellon legal accrual |  | 441 |  |  | 440 |
Other |  | 322 |  |  | 304 |
Total other current liabilities |  | $ | 1,798 |  |  | $ | 1,798 |

Other long-term liabilities as of March 31, 2017 and December 31, 2016 are detailed below.

|  | March 31, 2017 |  | December 31, 2016
|  | ($ in millions)
CHK Utica ORRI conveyance obligation(a) |  | $ | 153 |  |  | $ | 160 |
Unrecognized tax benefits |  | 97 |  |  | 97 |
Other |  | 118 |  |  | 126 |
Total other long-term liabilities |  | $ | 368 |  |  | $ | 383 |

____________________________________________

(a) | The CHK Utica L.L.C. investors’ right to receive proportionately a 3% overriding royalty interest (ORRI) in the first 1,500 net wells drilled on our Utica Shale leasehold is subject to an increase to 4% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, that runs through 2023. The liability represents the obligation to deliver future ORRIs. As of March 31, 2017, and December 31, 2016, approximately $49 million and $43 million of the total $202 million and $203 million obligations, respectively, are recorded in other current liabilities.

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

6. | Equity

Common Stock
A summary of the changes in our common shares issued for the Current Quarter and the Prior Quarter is detailed below.

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | (in thousands)
Shares issued as of January 1 |  | 896,279 |  |  | 664,796 |
Exchange of convertible notes |  | — |  |  | 14,699 |
Exchange of senior notes |  | — |  |  | 2,556 |
Exchange/conversion of preferred stock |  | 9,966 |  |  | 1,022 |
Restricted stock issuances (net of forfeitures and cancellations) |  | 1,798 |  |  | 1,488 |
Shares issued as of March 31 |  | 908,043 |  |  | 684,561 |

Preferred Stock
Outstanding shares of our preferred stock for the Current Quarter and the Prior Quarter are detailed below.

|  | 5.75% |  | 5.75% (A) |  | 4.50% |  | 5.00% (2005B)
|  | (in thousands)
Shares outstanding as of January 1, 2017 |  | 843 |  |  | 476 |  |  | 2,559 |  |  | 1,962 |
Preferred stock conversions/exchanges(a) |  | (73 | ) |  | (13 | ) |  | — |  |  | (151 | )
Shares outstanding as of March 31, 2017 |  | 770 |  |  | 463 |  |  | 2,559 |  |  | 1,811 |
Shares outstanding as of January 1, 2016 |  | 1,497 |  |  | 1,100 |  |  | 2,559 |  |  | 2,096 |
Preferred stock conversions/exchanges(b) |  | (25 | ) |  | (1 | ) |  | — |  |  | — |
Shares outstanding as of March 31, 2016 |  | 1,472 |  |  | 1,099 |  |  | 2,559 |  |  | 2,096 |

____________________________________________

(a) | In the Current Quarter, holders of our 5.75% Cumulative Convertible Preferred Stock exchanged 72,600 shares into 7,442,156 shares of common stock, holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock exchanged 12,500 shares into 1,205,923 shares of common stock and holders of our 5.00% (Series 2005B) Cumulative Convertible Preferred Stock exchanged 150,948 shares into 1,317,756 shares of common stock. In connection with the exchanges, we recognized a loss equal to the excess of the fair value of all common stock issued in exchange for the preferred stock over the fair value of the common stock issuable pursuant to the original terms of the preferred stock. The loss of $41 million is reflected as a reduction to net income available to common stockholders for the purpose of calculating earnings per common share.

(b) | In the Prior Quarter, holders of our 5.75% Cumulative Convertible Preferred Stock converted 24,601 shares into 975,488 shares of common stock and holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock converted 1,201 shares into 46,018 shares of common stock.

Dividends
Dividends declared on our preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings exists after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, payments constitute a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Dividends on our outstanding preferred stock are payable quarterly. We may pay dividends on our 5.00% Cumulative Convertible Preferred Stock (Series 2005B) and our 4.50% Cumulative Convertible Preferred Stock in cash, common stock or a combination thereof, at our option. Dividends on both series of our 5.75% Cumulative Convertible Non-Voting Preferred Stock are payable only in cash.
In the Prior Quarter, we suspended dividend payments on our convertible preferred stock to provide additional liquidity in the depressed commodity price environment that existed throughout 2016. In the Current Quarter, we reinstated the payment of dividends on each series of our outstanding convertible preferred stock and paid our dividends in arrears.
Accumulated Other Comprehensive Income (Loss)
For the Current Quarter and the Prior Quarter, changes in accumulated other comprehensive income (loss) for cash flow hedges, net of tax, are detailed below.

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
Balance, as of January 1 |  | $ | (96 | ) |  | $ | (99 | )
Other comprehensive income before reclassifications |  | 4 |  |  | (4 | )
Amounts reclassified from accumulated other comprehensive income |  | 10 |  |  | 4 |
Net other comprehensive income (loss) |  | 14 |  |  | — |
Balance, as of March 31 |  | $ | (82 | ) |  | $ | (99 | )

For the Current Quarter and the Prior Quarter, net losses on cash flow hedges for commodity contracts reclassified from accumulated other comprehensive income (loss), net of tax, to oil, natural gas and NGL revenues in the condensed consolidated statements of operations were $15 million and $4 million, respectively.

7. | Share-Based Compensation

Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units (PSUs) 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 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 Quarter is presented below.

|  | Shares of Unvested Restricted Stock |  | Weighted Average Grant Date Fair Value
|  | (in thousands) |  |
Unvested restricted stock as of January 1, 2017 |  | 9,092 |  |  | $ | 11.39 |
Granted |  | 9,034 |  |  | $ | 5.45 |
Vested |  | (3,226 | ) |  | $ | 14.39 |
Forfeited |  | (101 | ) |  | $ | 10.43 |
Unvested restricted stock as of March 31, 2017 |  | 14,799 |  |  | $ | 7.12 |

The aggregate intrinsic value of restricted stock that vested during the Current Quarter was approximately $19 million based on the stock price at the time of vesting.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
As of March 31, 2017, there was approximately $85 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 2.25 years.
Stock Options. In the Current Quarter and the Prior Quarter, 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 the Company’s common stock on the grant date. Outstanding options expire seven 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 an average of 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 the Company's dividend policy, over the expected life of the option. The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Quarter.

Expected option life – years |  | 6.0 |
Volatility |  | 62.42 | %
Risk-free interest rate |  | 2.17 | %
Dividend yield |  | — | %

The following table provides information related to stock option activity in the Current Quarter.

|  | 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, 2017 |  | 8,593 |  |  | $ | 11.88 |  |  | 7.22 |  | $ | 14 |
Granted |  | 9,192 |  |  | $ | 5.45 |  |  |  |  |
Exercised |  | — |  |  | $ | — |  |  |  |  | $ | — |
Expired |  | (276 | ) |  | $ | 18.74 |  |  |  |  |
Forfeited |  | (66 | ) |  | $ | 5.45 |  |  |  |  |
Outstanding as of March 31, 2017 |  | 17,443 |  |  | $ | 8.41 |  |  | 8.65 |  | $ | 14 |
Exercisable as of March 31, 2017 |  | 4,526 |  |  | $ | 15.69 |  |  | 6.50 |  | $ | 3 |

___________________________________________

(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 March 31, 2017, there was $34 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 2.71 years.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter and the Prior Quarter.

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
General and administrative expenses |  | $ | 8 |  |  | $ | 8 |
Oil and natural gas properties |  | 4 |  |  | 4 |
Oil, natural gas and NGL production expenses |  | 3 |  |  | 3 |
Marketing, gathering and compression expenses |  | — |  |  | 1 |
Total restricted stock and stock option compensation |  | $ | 15 |  |  | $ | 16 |

Liability-Classified Awards
Performance Share Units. We have granted PSUs to senior management that vest ratably over a three-year term and are settled in cash on the third anniversary of the awards. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors, which include total shareholder return (TSR) and, for certain of the awards, operational performance goals such as finding and development costs and production levels.
For PSUs granted in 2017 and 2016, the TSR component can range from 0% to 100% and the operational component can range from 0% to 100%, resulting in a maximum payout of 200%. For PSUs granted in 2015, the TSR component can range from 0% to 100%, and each of the two operational components can range from 0% to 50% resulting in a maximum total payout of 200%. Compensation expense associated with PSU grants 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 the Company’s estimates of the underlying performance measures. The Company utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the PSUs. The payout percentage for all PSU grants is capped at 100% if the Company's absolute TSR is less than zero.

Volatility |  | 80.65 | %
Risk-free interest rate |  | 1.54 | %
Dividend yield for value of awards |  | — | %

The following table presents a summary of our 2017, 2016 and 2015 PSU awards.

|  |  |  | Grant Date Fair Value |  | March 31, 2017
|  | Units |  |  | Fair Value |  | Vested Liability
|  |  |  | ($ in millions) |  |  |  |
2017 Awards: |  |  |  |  |  |  |  |
Payable 2020 |  | 1,256,295 |  |  | $ | 8 |  |  | $ | 8 |  |  | $ | 1 |
2016 Awards: |  |  |  |  |  |  |  |
Payable 2019 |  | 2,348,893 |  |  | $ | 10 |  |  | $ | 17 |  |  | $ | 11 |
2015 Awards: |  |  |  |  |  |  |  |
Payable 2018 |  | 629,694 |  |  | $ | 13 |  |  | $ | 2 |  |  | $ | 2 |

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
PSU Compensation. We recognized the following compensation costs (credits) related to PSUs for the Current Quarter and the Prior Quarter.

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
General and administrative expenses |  | $ | (2 | ) |  | $ | 2 |
Restructuring and other termination costs |  | — |  |  | 1 |
Total PSU compensation |  | $ | (2 | ) |  | $ | 3 |

8. | Derivative and Hedging Activities

Chesapeake uses derivative instruments to secure attractive pricing and margins on its share of expected production, to reduce its exposure to fluctuations in future commodity prices and to protect its expected operating cash flow against significant market movements or volatility. Chesapeake also uses derivative instruments, when applicable, to mitigate a portion of its exposure to foreign currency exchange rate fluctuations. All of our commodity 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.
Oil, Natural Gas and NGL Derivatives
As of March 31, 2017 and December 31, 2016, our oil, natural gas and NGL derivative instruments consisted of the following types of instruments:

• | Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.

• | Options: Chesapeake sells, and occasionally buys, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty the excess on sold call options and Chesapeake receives 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.

• | 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, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call strike prices, no payments are due from either party.

• | Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. Chesapeake receives the fixed price differential and pays 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 March 31, 2017 and December 31, 2016 are provided below.

|  | March 31, 2017 |  | December 31, 2016
|  | Volume |  | Fair Value |  | Volume |  | Fair Value
|  |  |  | ($ in millions) |  |  |  | ($ in millions)
Oil (mmbbl): |  |  |  |  |  |  |  |
Fixed-price swaps |  | 19 |  |  | $ | (26 | ) |  | 23 |  |  | $ | (140 | )
Call options |  | 4 |  |  | — |  |  | 5 |  |  | (1 | )
Total oil |  | 23 |  |  | (26 | ) |  | 28 |  |  | (141 | )
Natural gas (tbtu): |  |  |  |  |  |  |  |
Fixed-price swaps |  | 622 |  |  | (126 | ) |  | 719 |  |  | (349 | )
Collars |  | 48 |  |  | 3 |  |  | 60 |  |  | (9 | )
Call options |  | 102 |  |  | — |  |  | 114 |  |  | — |
Basis protection swaps |  | 18 |  |  | (2 | ) |  | 31 |  |  | (5 | )
Total natural gas |  | 790 |  |  | (125 | ) |  | 924 |  |  | (363 | )
NGL (mmgal): |  |  |  |  |  |  |  |
Fixed-price swaps |  | 27 |  |  | 1 |  |  | 53 |  |  | — |
Total estimated fair value |  |  |  | $ | (150 | ) |  |  |  | $ | (504 | )

We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. See further discussion below under Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss).
Interest Rate Derivatives
As of March 31, 2017 and December 31, 2016, there were no interest rate derivatives outstanding.
We have terminated fair value hedges related to certain of our senior notes. Gains and losses related to these terminated hedges will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next four years, we will recognize $3 million in net gains related to these transactions.
Foreign Currency Derivatives
We were party to cross currency swaps to mitigate our exposure to foreign currency exchange rate fluctuations. During the Current Quarter, both our 6.25% Euro-denominated Senior Notes due 2017 and cross currency swaps for the same principal amount matured. Upon maturity of the notes, t he counterparties paid us €246 million and we paid the counterparties $327 million. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. The swaps were designated as cash flow hedges and, because they were entirely effective in having eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates, changes in their fair value did not impact earnings. The fair values of the cross currency swaps were recorded on the condensed consolidated balance sheet as a liability of $73 million as of December 31, 2016.
Supply Contract Derivatives
From time to time and in the normal course of business, our marketing subsidiary enters into supply contracts under which we commit to deliver a predetermined quantity of natural gas to certain counterparties in an attempt to earn attractive margins. Under certain contracts, we receive a sales price that is based on the price of a product other than natural gas, thereby creating an embedded derivative requiring bifurcation. The bifurcated derivative is measured at fair value on a quarterly basis and in the Prior Quarter resulted in an unrealized gain of $20 million which was included in marketing, gathering and compression revenues in our condensed consolidated statements of operations.
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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 March 31, 2017 and December 31, 2016 on a gross basis and after same-counterparty netting:

Balance Sheet Classification |  | Gross Fair Value |  | Amounts Netted in the Condensed Consolidated Balance Sheets |  | Net Fair Value Presented in the Condensed Consolidated Balance Sheet
|  | ($ in millions)
As of March 31, 2017 |  |  |  |  |  |
Commodity Contracts: |  |  |  |  |  |
Short-term derivative asset |  | $ | 5 |  |  | $ | (4 | ) |  | $ | 1 |
Short-term derivative liability |  | (161 | ) |  | 4 |  |  | (157 | )
Long-term derivative asset |  | 8 |  |  | (1 | ) |  | 7 |
Long-term derivative liability |  | (2 | ) |  | 1 |  |  | (1 | )
Total commodity contracts |  | (150 | ) |  | — |  |  | (150 | )
Total derivatives |  | $ | (150 | ) |  | $ | — |  |  | $ | (150 | )
As of December 31, 2016 |  |  |  |  |  |
Commodity Contracts: |  |  |  |  |  |
Short-term derivative asset |  | $ | 1 |  |  | $ | (1 | ) |  | $ | — |
Short-term derivative liability |  | (490 | ) |  | 1 |  |  | (489 | )
Long-term derivative liability |  | (15 | ) |  | — |  |  | (15 | )
Total commodity contracts |  | (504 | ) |  | — |  |  | (504 | )
Foreign Currency Contracts:(a) |  |  |  |  |  |
Long-term derivative liability |  | (73 | ) |  | — |  |  | (73 | )
Total foreign currency contracts |  | (73 | ) |  | — |  |  | (73 | )
Total derivatives |  | $ | (577 | ) |  | $ | — |  |  | $ | (577 | )

____________________________________________

(a) | Designated as cash flow hedging instruments.

As of March 31, 2017 and December 31, 2016, we did not have any cash collateral balances for these derivatives.
Effect of Derivative Instruments – Condensed Consolidated Statements of Operations
The components of oil, natural gas and NGL revenues for the Current Quarter and the Prior Quarter are presented below.

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
Oil, natural gas and NGL revenues |  | $ | 1,147 |  |  | $ | 812 |
Gains (losses) on undesignated oil, natural gas and NGL derivatives |  | 332 |  |  | 192 |
Losses on terminated cash flow hedges |  | (10 | ) |  | (11 | )
Total oil, natural gas and NGL revenues |  | $ | 1,469 |  |  | $ | 993 |

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The components of marketing, gathering and compression revenues for the Current Quarter and the Prior Quarter are presented below.

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
Marketing, gathering and compression revenues |  | $ | 1,284 |  |  | $ | 940 |
Gains (losses) on undesignated supply contract derivatives |  | — |  |  | 20 |
Total marketing, gathering and compression revenues |  | $ | 1,284 |  |  | $ | 960 |

The components of interest expense for the Current Quarter and the Prior Quarter are presented below.

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
Interest expense on senior notes |  | $ | 136 |  |  | $ | 157 |
Interest expense on term loan |  | 32 |  |  | — |
Amortization of loan discount, issuance costs and other |  | 9 |  |  | 10 |
Amortization of premium associated with troubled debt restructuring |  | (41 | ) |  | (42 | )
Interest expense on revolving credit facilities |  | 9 |  |  | 5 |
(Gains) losses on undesignated interest rate derivatives |  | 1 |  |  | — |
Capitalized interest |  | (51 | ) |  | (68 | )
Total interest expense |  | $ | 95 |  |  | $ | 62 |

Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss)
A reconciliation of the changes in accumulated other comprehensive income (loss) in our condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | Before Tax |  | After Tax |  | Before Tax |  | After Tax
|  | ($ in millions)
Balance, as of January 1 |  | $ | (153 | ) |  | $ | (96 | ) |  | $ | (160 | ) |  | $ | (99 | )
Net change in fair value |  | 4 |  |  | 4 |  |  | (7 | ) |  | (4 | )
Losses reclassified to income |  | 10 |  |  | 10 |  |  | 11 |  |  | 4 |
Balance, as of March 31 |  | $ | (139 | ) |  | $ | (82 | ) |  | $ | (156 | ) |  | $ | (99 | )

The accumulated other comprehensive loss, as of March 31, 2017, represents the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. Deferred gain or loss amounts will be recognized in earnings in the month in which the originally forecasted hedged production occurs. As of March 31, 2017, we expect to transfer approximately $20 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.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
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 rated investment grade 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 March 31, 2017, our oil, natural gas and NGL derivative instruments were spread among 10 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, which allows us to reduce any letters of credit posted as security with those counterparties. In addition, with other counterparties we enter into bilateral hedging agreements. The counterparties’ and our obligations under certain of 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.
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, NGL and cross currency 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 March 31, 2017 and December 31, 2016:

|  | 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 March 31, 2017 |  |  |  |  |  |  |  |
Derivative Assets (Liabilities): |  |  |  |  |  |  |  |
Commodity assets |  | $ | — |  |  | $ | 10 |  |  | $ | 3 |  |  | $ | 13 |
Commodity liabilities |  | — |  |  | (163 | ) |  | — |  |  | (163 | )
Total derivatives |  | $ | — |  |  | $ | (153 | ) |  | $ | 3 |  |  | $ | (150 | )
As of December 31, 2016 |  |  |  |  |  |  |  |
Derivative Assets (Liabilities): |  |  |  |  |  |  |  |
Commodity assets |  | $ | — |  |  | $ | 1 |  |  | $ | — |  |  | $ | 1 |
Commodity liabilities |  | — |  |  | (495 | ) |  | (10 | ) |  | (505 | )
Foreign currency liabilities |  | — |  |  | (73 | ) |  | — |  |  | (73 | )
Total derivatives |  | $ | — |  |  | $ | (567 | ) |  | $ | (10 | ) |  | $ | (577 | )

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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 Chesapeake’s financial assets (liabilities) classified as Level 3 during the Current Quarter and the Prior Quarter is presented below.

|  | Commodity Derivatives |  | Supply Contracts
|  | ($ in millions)
Balance, as of January 1, 2017 |  | $ | (10 | ) |  | $ | — |
Total gains (losses) (realized/unrealized): |  |  |  |
Included in earnings(a) |  | 12 |  |  | — |
Total purchases, issuances, sales and settlements: |  |  |  |
Settlements |  | 1 |  |  | — |
Balance, as of March 31, 2017 |  | $ | 3 |  |  | $ | — |
Balance, as of January 1, 2016 |  | $ | (91 | ) |  | $ | 297 |
Total gains (losses) (realized/unrealized): |  |  |  |
Included in earnings(a) |  | 25 |  |  | 33 |
Total purchases, issuances, sales and settlements: |  |  |  |
Settlements |  | 18 |  |  | (13 | )
Balance, as of March 31, 2016 |  | $ | (48 | ) |  | $ | 317 |

___________________________________________

(a) |  | Oil, Natural Gas and NGL Sales |  | Marketing, Gathering and Compression Revenue
|  | 2017 |  | 2016 |  | 2017 |  | 2016
|  | ($ in millions)
Total gains (losses) included in earnings for the period |  | $ | 12 |  |  | $ | 25 |  |  | $ | — |  |  | $ | 20 |
Change in unrealized gains (losses) related to assets still held at reporting date |  | $ | 5 |  |  | $ | 21 |  |  | $ | — |  |  | $ | 20 |

Qualitative and Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements
The significant unobservable inputs for Level 3 derivative contracts include unpublished forward prices of natural gas, market volatility and credit risk of counterparties. Changes in these inputs impact 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, and adverse changes to our counterparties’ creditworthiness decreases the fair value of our 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 March 31, 2017:

Instrument Type |  | Unobservable Input |  | Range |  | Weighted Average |  | Fair Value March 31, 2017
|  |  |  |  |  |  |  | ($ in millions)
Oil trades |  | Oil price volatility curves |  | 18.22% – 24.10% |  | 22.97% |  | $ | — |
Natural gas trades |  | Natural gas price volatility curves |  | 21.37% – 52.18% |  | 38.10% |  | $ | 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 accounted for the sales of oil and natural gas properties discussed below as adjustments to capitalized costs, with no recognition of gain or loss as the sales did not involve a significant change in proved reserves or significantly alter the relationship between costs and proved reserves.
In the Current Quarter, 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 post-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 Current Quarter, we received proceeds of $20 million for the sale of other oil and natural gas properties.
In the Prior Quarter, we received proceeds of $140 million for the sale of other oil and natural gas properties, partially offset by $78 million of post-closing adjustments and other settlements for prior period divestitures.
Volumetric Production Payments
From time to time, we have sold certain of our producing assets located in more mature producing regions through the sale of VPPs. 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. For all of our VPP transactions, we novated to each of the respective VPP buyers hedges that covered all VPP volumes sold. 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 condensed 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. Pursuant to SEC guidelines, the estimates used for purposes of determining the cost center ceiling and the standardized measure are based on current costs. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. The costs that will apply in the future 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.
For accounting purposes, cash proceeds from the sale of VPPs were reflected as a reduction of oil and natural gas properties with no gain or loss recognized, and our proved reserves were reduced accordingly. We have also 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.
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
As of March 31, 2017, 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 produced on behalf of our VPP buyers during the Current Quarter and the Prior Quarter were as follows:

Three Months Ended March 31, 2017
VPP # |  | Oil |  | Natural Gas |  | NGL |  | Total
|  | (mbbl) |  | (bcf) |  | (mbbl) |  | (bcfe)
9 |  | 35.9 |  |  | 3.1 |  |  | 82.8 |  |  | 3.8 |
Three Months Ended March 31, 2016
VPP # |  | Oil |  | Natural Gas |  | NGL |  | Total
|  | (mbbl) |  | (bcf) |  | (mbbl) |  | (bcfe)
10(a) |  | 66.0 |  |  | 1.8 |  |  | 222.7 |  |  | 3.5 |
9 |  | 39.4 |  |  | 3.4 |  |  | 89.3 |  |  | 4.1 |
4(a) |  | 10.1 |  |  | 1.9 |  |  | — |  |  | 2.0 |
3(a) |  | — |  |  | 1.5 |  |  | — |  |  | 1.5 |
2(a) |  | — |  |  | 0.9 |  |  | — |  |  | 0.9 |
1(a) |  | — |  |  | 3.3 |  |  | — |  |  | 3.3 |
|  | 115.5 |  |  | 12.8 |  |  | 312.0 |  |  | 15.3 |

____________________________________________

(a) | In connection with certain asset divestitures in 2016, we purchased the remaining oil and natural gas interests previously sold in connection with VPP #10, VPP #4, VPP #3, VPP #2 and VPP #1. A majority of the oil and natural gas interests purchased were subsequently sold to the buyers of the assets.

The volumes remaining to be delivered on behalf of our VPP buyers as of March 31, 2017 were as follows:

|  |  |  | Volume Remaining as of March 31, 2017
VPP # |  | Term Remaining |  | Oil |  | Natural Gas |  | NGL |  | Total
|  | (in months) |  | (mmbbl) |  | (bcf) |  | (mmbbl) |  | (bcfe)
9 |  | 47 |  | 0.5 |  |  | 42.8 |  |  | 1.1 |  |  | 52.5 |

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

10. | Variable Interest Entities

We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform a qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.
Consolidated VIE
Chesapeake Granite Wash Trust (the Trust) is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Trust and because the royalty interest owners, other than Chesapeake, do not have the ability to exercise substantial liquidation rights. Our ownership in the Trust and our previous obligations under the development agreement constitute variable interests. We have determined that we are the primary beneficiary of the Trust because (i) we have the power to direct the activities that most significantly impact the economic performance of the Trust via our operation of the majority of the producing wells and the completed development wells, and (ii) as a result of the subordination and incentive thresholds applicable to the subordinated units we hold in the Trust, we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to the Trust. As a result, we consolidate the Trust in our financial statements, and the common units of the Trust owned by third parties are reflected as a noncontrolling interest. As of March 31, 2017 and December 31, 2016, we had $256 million and $257 million, respectively, of noncontrolling interests on our condensed consolidated balance sheets attributable to the Trust. In the Current Quarter and the Prior Quarter, we had $1 million and a nominal amount, respectively, of net income attributable to the Trust’s noncontrolling interests recorded in our condensed consolidated statements of operations.
The Trust is a consolidated entity whose legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake. In consolidation, as of March 31, 2017, $1 million of cash and cash equivalents, $488 million of proved oil and natural gas properties, $459 million of accumulated depreciation, depletion and amortization and $3 million of other current liabilities were attributable to the Trust. We have presented parenthetically on the face of the condensed consolidated balance sheets the assets of the Trust that can be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors do not have recourse to the general credit of Chesapeake.
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

11. | Impairments

Impairments of Oil and Natural Gas Properties
Our proved oil and natural gas properties are subject to quarterly full cost ceiling tests. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. Estimated future net revenues for the quarterly ceiling limit are calculated using the average of commodity prices on the first day of the month over the trailing 12-month period. In the Prior Quarter, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment in the carrying value of our oil and natural gas properties of $997 million.
Impairments of Fixed Assets and Other
We review our long-lived assets, other than oil and natural gas properties, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable. We recognize an impairment if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. A summary of our impairments of fixed assets by asset class and other charges for the Current Quarter and the Prior Quarter is as follows:

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
Natural gas compressors |  | $ | — |  |  | $ | 20 |
Buildings and land |  | — |  |  | 7 |
Other |  | 391 |  |  | 11 |
Total impairments of fixed assets and other |  | $ | 391 |  |  | $ | 38 |

Other. In the Current Quarter, we paid $290 million to assign an oil transportation agreement to a third party. In addition, we terminated future natural gas transportation commitments related to divested assets for a cash payment of $103 million.
Nonrecurring Fair Value Measurements. Fair value measurements for certain of the impairments were based on recent sales information for comparable assets. As the fair value was estimated using the market approach based on recent prices from orderly sales transactions for comparable assets between market participants, these values were classified as Level 2 in the fair value hierarchy. Other inputs used were not observable in the market; these values were classified as Level 3 in the fair value hierarchy.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

12. | Income Taxes

A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, and we consider the tax consequences in the jurisdiction where taxable income is generated, to determine whether a valuation allowance is required. The evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry.
Based on our estimated operating results for the subsequent quarters, we project being in a net deferred tax asset position as of December 31, 2017. We believe it is more likely than not that these deferred tax assets will not be realized. Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant piece of objective negative evidence evaluated is the projected cumulative loss incurred over the three-year period ending December 31, 2017. The objective negative evidence limits the ability to consider other subjective positive evidence, such as our projections for future growth. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future expected growth.

13. | Fair Value Measurements

Recurring Fair Value Measurements
Other Current Assets. Assets related to Chesapeake’s 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 Chesapeake’s 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 March 31, 2017 and December 31, 2016:

|  | 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 March 31, 2017 |  |  |  |  |  |  |  |
Financial Assets (Liabilities): |  |  |  |  |  |  |  |
Other current assets |  | $ | 55 |  |  | $ | — |  |  | $ | — |  |  | $ | 55 |
Other current liabilities |  | (56 | ) |  | — |  |  | — |  |  | (56 | )
Total |  | $ | (1 | ) |  | $ | — |  |  | $ | — |  |  | $ | (1 | )
As of December 31, 2016 |  |  |  |  |  |  |  |
Financial Assets (Liabilities): |  |  |  |  |  |  |  |
Other current assets |  | $ | 49 |  |  | $ | — |  |  | $ | — |  |  | $ | 49 |
Other current liabilities |  | (51 | ) |  | — |  |  | — |  |  | (51 | )
Total |  | $ | (2 | ) |  | $ | — |  |  | $ | — |  |  | $ | (2 | )

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.
Nonrecurring Fair Value Measurements
See Note 11 regarding nonrecurring fair value measurements.
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

14. | Segment Information

As of March 31, 2017, we have two reportable operating segments, each of which is managed separately because of the nature of its operations. The exploration and production operating segment is responsible for finding and producing oil, natural gas and NGL. The marketing, gathering and compression operating segment is responsible for marketing, gathering and compression of oil, natural gas and NGL.
Management evaluates the performance of our segments based upon income (loss) before income taxes. Revenues from the sale of oil, natural gas and NGL related to Chesapeake’s ownership interests by our marketing, gathering and compression operating segment are reflected as revenues within our exploration and production operating segment. These amounts totaled $1.120 billion and $783 million for the Current Quarter and the Prior Quarter, respectively.
The following table presents selected financial information for Chesapeake’s operating segments:

|  | Exploration and Production |  | Marketing, Gathering and Compression |  | Other |  | Intercompany Eliminations |  | Consolidated Total
|  | ($ in millions)
Three Months Ended March 31, 2017 |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 1,469 |  |  | $ | 2,404 |  |  | $ | — |  |  | $ | (1,120 | ) |  | $ | 2,753 |
Intersegment revenues |  | — |  |  | (1,120 | ) |  | — |  |  | 1,120 |  |  | — |
Total Revenues |  | $ | 1,469 |  |  | $ | 1,284 |  |  | $ | — |  |  | $ | — |  |  | $ | 2,753 |
Income (Loss) Before Income Taxes |  | $ | 567 |  |  | $ | (386 | ) |  | $ | (10 | ) |  | $ | (29 | ) |  | $ | 142 |
Three Months Ended March 31, 2016 |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 993 |  |  | $ | 1,743 |  |  | $ | — |  |  | $ | (783 | ) |  | $ | 1,953 |
Intersegment revenues |  | — |  |  | (783 | ) |  | — |  |  | 783 |  |  | — |
Total Revenues |  | $ | 993 |  |  | $ | 960 |  |  | $ | — |  |  | $ | — |  |  | $ | 1,953 |
Income (Loss) Before Income Taxes (as previously reported) |  | $ | (895 | ) |  | $ | 40 |  |  | $ | (9 | ) |  | $ | (57 | ) |  | $ | (921 | )
Income (Loss) Before Income Taxes (as revised) |  | $ | (1,042 | ) |  | $ | 40 |  |  | $ | (9 | ) |  | $ | (57 | ) |  | $ | (1,068 | )
As of March 31, 2017 |  |  |  |  |  |  |  |  |  |
Total Assets |  | $ | 10,147 |  |  | $ | 918 |  |  | $ | 1,031 |  |  | $ | (397 | ) |  | $ | 11,699 |
As of December 31, 2016 |  |  |  |  |  |  |  |  |  |
Total Assets |  | $ | 11,249 |  |  | $ | 1,118 |  |  | $ | 1,059 |  |  | $ | (398 | ) |  | $ | 13,028 |

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

15. | Recently Issued Accounting Standards

In May 2014, the FASB issued updated revenue recognition guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and international financial reporting standards. The new standard requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration the company expects to receive in the exchange. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early application permitted after December 31, 2016. In March 2016, the FASB issued an update clarifying the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued an update clarifying the identification of performance obligations and licensing implementations guidance. In May 2016, the FASB issued an update clarifying guidance in a few narrow areas and added some practical expedients to the guidance. We are in the process of assessing differences between the new revenue standard and current accounting practices. In addition, w e are evaluating the impact of this guidance on our condensed consolidated financial statements and related disclosures.
In February 2016, the FASB issued updated lease accounting guidance requiring companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures.
In March 2016, the FASB issued new guidance that will result in fewer put or call options embedded in debt instruments qualifying for separate derivative accounting because companies will not be required to assess whether the contingent event, such as change in control or an IPO, is related to interest rates or credit risks. This standard is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. The adoption of this guidance did not have a material impact on our consolidated financial statements and related disclosures.
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ITEM 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations

Financial Data
The following table sets forth certain information regarding our production volumes, oil, natural gas and NGL sales, average sales prices received, and other operating income and expenses for the periods indicated:

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
Net Production: |  |  |  |
Oil (mmbbl) |  | 8 |  |  | 9 |
Natural gas (bcf) |  | 211 |  |  | 276 |
NGL (mmbbl) |  | 5 |  |  | 6 |
Oil equivalent (mmboe)(a) |  | 48 |  |  | 61 |
Oil, Natural Gas and NGL Sales ($ in millions): |  |  |  |
Oil sales |  | $ | 378 |  |  | $ | 255 |
Oil derivatives – realized gains (losses)(b) |  | 11 |  |  | 73 |
Oil derivatives – unrealized gains (losses)(b) |  | 94 |  |  | (72 | )
Total oil sales |  | 483 |  |  | 256 |
Natural gas sales |  | 653 |  |  | 483 |
Natural gas derivatives – realized gains (losses)(b) |  | (16 | ) |  | 150 |
Natural gas derivatives – unrealized gains (losses)(b) |  | 231 |  |  | 30 |
Total natural gas sales |  | 868 |  |  | 663 |
NGL sales |  | 116 |  |  | 74 |
NGL derivatives – realized gains (losses)(b) |  | 1 |  |  | — |
NGL derivatives – unrealized gains (losses)(b) |  | 1 |  |  | — |
Total NGL sales |  | 118 |  |  | 74 |
Total oil, natural gas and NGL sales |  | $ | 1,469 |  |  | $ | 993 |
Average Sales Price (excluding gains (losses) on derivatives): |  |  |  |
Oil ($ per bbl) |  | $ | 50.24 |  |  | $ | 29.34 |
Natural gas ($ per mcf) |  | $ | 3.10 |  |  | $ | 1.75 |
NGL ($ per bbl) |  | $ | 23.78 |  |  | $ | 11.44 |
Oil equivalent ($ per boe) |  | $ | 24.13 |  |  | $ | 13.28 |
Average Sales Price (including realized gains (losses) on derivatives): |  |  |  |
Oil ($ per bbl) |  | $ | 51.72 |  |  | $ | 37.74 |
Natural gas ($ per mcf) |  | $ | 3.02 |  |  | $ | 2.29 |
NGL ($ per bbl) |  | $ | 24.04 |  |  | $ | 11.44 |
Oil equivalent ($ per boe) |  | $ | 24.06 |  |  | $ | 16.93 |
Other Operating Income ($ in millions): |  |  |  |
Marketing, gathering and compression net margin(c)(d) |  | $ | (44 | ) |  | $ | 18 |

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|  | Three Months Ended March 31,
|  | 2017 |  | 2016
Expenses ($ per boe): |  |  |  |
Oil, natural gas and NGL production |  | $ | 2.84 |  |  | $ | 3.36 |
Oil, natural gas and NGL gathering, processing and transportation |  | $ | 7.47 |  |  | $ | 7.88 |
Production taxes |  | $ | 0.47 |  |  | $ | 0.30 |
General and administrative |  | $ | 1.35 |  |  | $ | 0.79 |
Oil, natural gas and NGL depreciation, depletion and amortization |  | $ | 4.15 |  |  | $ | 4.30 |
Depreciation and amortization of other assets |  | $ | 0.44 |  |  | $ | 0.48 |
Interest expense(e) |  | $ | 1.97 |  |  | $ | 0.98 |
Interest Expense ($ in millions): |  |  |  |
Interest expense |  | $ | 94 |  |  | $ | 62 |
Interest rate derivatives – realized (gains) losses(f) |  | (1 | ) |  | (3 | )
Interest rate derivatives – unrealized (gains) losses(f) |  | 2 |  |  | 3 |
Total interest expense |  | $ | 95 |  |  | $ | 62 |

___________________________________________

(a) | Oil equivalent is based on six mcf of natural gas to one barrel of oil or one barrel of NGL. This ratio reflects an energy content equivalency and not a price or revenue equivalency.

(b) | Realized gains (losses) include the following items: (i) settlements and accruals for settlements of undesignated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains (losses) related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains (losses) include the change in fair value of open derivatives scheduled to settle against future period production revenues (including current period settlements for option premiums and early terminated derivatives) offset by amounts reclassified as realized gains (losses) during the period.

(c) | Includes revenue and operating costs. See Depreciation and Amortization of Other Assets under Results of Operations for details of the depreciation and amortization associated with our marketing, gathering and compression segment.

(d) | In the Prior Quarter, we recorded unrealized gains of $20 million on the fair value of our supply contract derivative. See Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of this report for discussion related to this instrument.

(e) | 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.

(f) | Realized (gains) losses include interest rate derivative settlements related to current period interest and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item. Unrealized (gains) losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.

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Overview
We own interests in approximately 21,900 oil and natural gas wells and produced an average of approximately 528 mboe per day in the Current Quarter, net to our interest. We have a large and geographically diverse resource base of onshore U.S. unconventional natural gas and liquids assets. We have leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas, the Utica Shale in Ohio, the Anadarko Basin in northwestern Oklahoma and the stacked pay in the Powder River Basin in Wyoming. Our natural gas resource plays are the Haynesville/Bossier Shales in northwestern Louisiana and East Texas and the Marcellus Shale in the northern Appalachian Basin in Pennsylvania. We also own oil and natural gas marketing and natural gas compression businesses.
Our Strategy
Chesapeake’s strategy is to create shareholder value through the development of our significant positions in premier U.S. onshore resource plays. In addition, we continue to focus our financial strategy on reducing debt and improving margins. We apply financial discipline to all aspects of our business with goals of increasing financial and operational flexibility. Our capital program is focused on investments that can improve our cash flow generating ability regardless of the commodity price environment. We plan to increase our capital expenditures in 2017 over 2016 levels to capture high rate-of-return opportunities in our oil and natural gas portfolio. These opportunities are a result of improved capital and operating efficiencies, including improved well performance, decreased drilling and completion costs per foot and decreased operating expenditures. We expect our anticipated production increases in the 2017 second half and into 2018 will position us to balance capital expenditures and operating cash flow in 2018 and beyond.
Our substantial inventory of hydrocarbon resources, including our undeveloped acreage, provides a strong foundation to create future value. Our focus on efficiencies and operational improvements has led to increased well productivity from longer laterals, improved completion techniques and base production improvements. Building on our strong and diverse asset base through increasing production and cash flow and further delineating our emerging new development opportunities, we believe that our dedication to financial discipline, the flexibility of our capital program, and our continued focus on safety and environmental stewardship will provide opportunities to create value for Chesapeake and its stakeholders in 2017 and beyond.
Operating Results
Our Current Quarter production of 48 mmboe consisted of 8 mmbbls of oil (16% on an oil equivalent basis), 211 bcf of natural gas (74% on an oil equivalent basis), and 5 mmbbls of NGL (10% on an oil equivalent basis). Our daily production for the Current Quarter averaged approximately 528 mboe, a decrease of 21% from the Prior Quarter. Compared to the Prior Quarter, average daily oil production decreased by 13% or approximately 12 mbbls per day; average daily natural gas production decreased by 23%, or approximately 694 mmcf per day; and average daily NGL production decreased by 24%, or approximately 17 mbbls per day. Our oil, natural gas and NGL production decreased primarily as a result of the sale of certain of our Mid-Continent and Barnett assets in 2016 as well as a significant reduction in drilling and completion activity in 2016. Adjusted for asset sales, our total daily production decreased 5% in the Current Quarter compared to the Prior Quarter. Our oil, natural gas and NGL revenues (excluding gains or losses on oil and natural gas derivatives) increased approximately $335 million to $1.147 billion in the Current Quarter compared to $812 million in the Prior Quarter, primarily due to increases in the prices received for oil, natural gas and NGL sold, partially offset by the production decreases described above. See Results of Operations below for additional details.
Capital Expenditures
Our drilling and completion capital expenditures during the Current Quarter were approximately $506 million and capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment were approximately $19 million, for a total of approximately $525 million. In the Current Quarter, we operated an average of 16 rigs, an increase of eight rigs, or 100%, compared to the Prior Quarter. As a result of higher drilling and completion activity, drilling and completion expenditures increased approximately $225 million in the Current Quarter compared to the Prior Quarter. The level of capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment increased approximately $3 million compared to the Prior Quarter.
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Our capitalized interest was approximately $51 million and $68 million in the Current Quarter and the Prior Quarter, respectively. The decrease in capitalized interest resulted from a lower average balance of our unproved oil and natural gas properties, the primary asset on which interest is capitalized. Including capitalized interest, total capital investments were approximately $576 million in the Current Quarter compared to $365 million for the Prior Quarter, an increase of 58%.
Based on planned activity levels for the remainder of 2017, we project that 2017 capital expenditures for drilling and completions, leasehold, geological and geophysical and other property and equipment will be $2.1 – $2.5 billion, inclusive of capitalized interest, as compared to $1.7 billion of capital expenditures in 2016. See Liquidity and Capital Resources for additional information on how we plan to fund our capital budget.
Strategic Developments
Debt Retirements
In the Current Quarter, we retired $908 million principal amount of our outstanding senior notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $982 million, which included the maturity of our 6.25% Euro-denominated Senior Notes due 2017 and corresponding cross currency swap.
Preferred Stock Exchanges
In January 2017, we completed private exchanges of an aggregate of approximately 10.0 million shares of our common stock for (i) 72,600 shares of 5.75% Cumulative Convertible Preferred Stock, (ii) 12,500 shares of 5.75% Cumulative Convertible Preferred Stock (Series A) and (iii) 150,948 shares of 5.00% Cumulative Convertible Preferred Stock (Series 2005B). The preferred stock exchanged represents approximately $100 million of liquidation value. These exchanges eliminated approximately $6 million of annual dividend obligations.
Divestitures
In the Current Quarter, 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 post-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.
In February 2017, we received proceeds of $20 million for the sale of other oil and natural gas properties.
Gathering, Processing and Transportation Agreements
In February 2017, we paid approximately $290 million to assign an oil transportation agreement to a third party. In addition, we terminated future natural gas transportation commitments related to divested assets for a cash payment of approximately $103 million.
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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 very volatile, and may be subject to wide fluctuations in the future. The substantial decline in oil, natural gas and NGL prices from 2014 levels has negatively affected the amount of cash we have available for capital expenditures and debt service. A substantial or extended decline in oil, natural gas and NGL prices could have a material impact on our financial position, results of operations, cash flows and on the quantities of reserves that we may economically produce. 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 ratios and covenants in our financing agreements.
As of March 31, 2017, we had a cash balance of $249 million compared to $882 million as of December 31, 2016, and we had a net working capital deficit of $1.428 billion, compared to a net working capital deficit of $1.506 billion as of December 31, 2016. 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 March 31, 2017, we had $3.088 billion of borrowing capacity available under our revolving credit facility, with no outstanding borrowings and $697 million utilized for various letters of credit (including the $461 million supersedeas bond with respect to the 2019 Notes litigation discussed below). 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.
In the Current Quarter, we took the following measures to improve our liquidity:

• | retired $908 million principal amount of our outstanding senior notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $982 million;

• | exchanged approximately 10 million shares of common stock for $100 million liquidation value of our preferred stock, eliminating $6 million of annual dividend obligations

Even though we have taken measures, as outlined above, to mitigate the liquidity concerns facing us for the next 12 months, there can be no assurance that these measures will satisfy our needs. We may continue to access the capital markets or otherwise incur debt to refin ance a portion of our outstanding indebtedness and improve our li q uidity.
As operator of a substantial portion of our oil and natural gas properties under development, 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 2017 capital expenditures, inclusive of capitalized interest, are $2.1 – $2.5 billion compared to our 2016 capital spending level of $1.7 billion. W e had liquidity (calculated as cash on hand and availability under our revolving credit facility), reflective of the pending relief of the letters of credit associated with our 2019 Notes litigation, of approximately $3.3 billion as of May 1, 2017. We expect to generate additional liquidity with proceeds from future sales of assets that we determine do not fit our strategic priorities. Management continues to review operational plans for the remainder of 2017 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL. 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.
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 May 1, 2017, we have received requests and posted approximately $293 million in collateral under such arrangements. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $431 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.
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In the Current Quarter, we repurchased $908 million principal amount of outstanding debt in the open market and through tender offers and exchanged approximately 10 million shares of common stock for approximately $100 million liquidation value of our outstanding preferred stock. Pursuant to the provisions of our 2.5% contingent convertible senior notes due 2037, we have offered to repurchase all of the outstanding notes at par on May 15, 2017. We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt and preferred stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.
On April 24, 2017, we received notice from the U.S. Supreme Court that it would not review our appeal of the decision by the U.S. District Court for the Southern District of New York regarding the redemption at par value of our 6.775% Senior Notes due 2019. As a result of this decision, on April 28, 2017 we paid $441 million with cash on hand and borrowings under the revolving credit facility and the related supersedeas bond was released. See Note 4 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the recent developments in this litigation.
To add more certainty to our future estimated cash flows by mitigating our downside exposure to lower commodity prices, as of May 1, 2017, we have downside price protection, through open swaps, on approximately 64% of our remaining projected 2017 oil production at an average price of $50.25 per bbl. We also have downside price protection, through open swaps and collars, on approximately 75% of our remaining projected 2017 natural gas production at an average price of $3.05 p er mcf, of which 4% is hedged under two-way collar arrangements based on an average bought put NYMEX price of $3.25 per mcf. We also have downside price protection, through open swaps, on approximately 4% of our remaining projected 2017 NGL production at an average price of $0.28 per gallon of ethane. In addition, we have downside price protection, through open swaps on 1.825 mmbbls of our 2018 oil production at an average price of $51.43 per bbl. We also have downside price protection, through open swaps and collars on 238 bcf of our 2018 gas production at an average price of $3.12 per mcf.
As highlighted above, we have taken measures to mitigate the liquidity concerns facing us in the remainder of 2017 and beyond, but there can be no assurance that such measures will satisfy our needs. Further, 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 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.
Sources of Funds
The following table presents the sources of our cash and cash equivalents for the Current Quarter and the Prior Quarter. 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.

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
Cash provided by (used in) operating activities |  | $ | 99 |  |  | $ | (421 | )
Proceeds from credit facility borrowings, net |  | — |  |  | 367 |
Divestitures of proved and unproved properties |  | 892 |  |  | 62 |
Sales of other property and equipment |  | 19 |  |  | 9 |
Total sources of cash and cash equivalents |  | $ | 1,010 |  |  | $ | 17 |

Cash provided by operating activities was $99 million in the Current Quarter compared to cash used in operating activities of $421 million in the Prior Quarter. The increase is primarily the result of higher realized prices for the oil, natural gas and NGL we sold, partially offset by lower volumes of oil, natural gas and NGL 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, impairments, gains or losses on sales of fixed assets, deferred income taxes and mark-to-market changes in our derivative instruments. See further discussion below under Results of Operations.
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We currently plan to use cash flow from operations, cash on hand and our revolving credit facility to fund our capital expenditures for the remainder of 2017. We expect to generate additional liquidity with proceeds from future sales of assets that we determine do not fit our strategic priorities. Under our revolving credit facilities, we borrowed and repaid $50 million in the Current Quarter and we borrowed $515 million and repaid $148 million in the Prior Quarter.
Uses of Funds
The following table presents the uses of our cash and cash equivalents for the Current Quarter and the Prior Quarter:

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
Oil and Natural Gas Expenditures: |  |  |  |
Drilling and completion costs |  | $ | 433 |  |  | $ | 265 |
Acquisitions of proved and unproved properties |  | 46 |  |  | 3 |
Interest capitalized on unproved leasehold |  | 49 |  |  | 64 |
Total oil and natural gas expenditures |  | 528 |  |  | 332 |
Other Uses of Cash and Cash Equivalents: |  |  |  |
Cash paid to repurchase debt |  | 982 |  |  | 472 |
Additions to other property and equipment |  | 3 |  |  | 10 |
Dividends paid |  | 114 |  |  | — |
Other |  | 16 |  |  | 12 |
Total other uses of cash and cash equivalents |  | 1,115 |  |  | 494 |
Total uses of cash and cash equivalents |  | $ | 1,643 |  |  | $ | 826 |

Our drilling and completion costs increased in the Current Quarter compared to the Prior Quarter primarily as a result of increased activity. During the Current Quarter, our average operated rig count was 16 rigs compared to an average operated rig count of eight rigs in the Prior Quarter and we completed 99 wells in the Current Quarter compared to 57 in the Prior Quarter.
In the Current Quarter, we used $982 million of cash to repurchase $908 million principal amount of debt. In the Prior Quarter, we used $472 million of cash to repurchase $558 million principal amount of debt.
We paid dividends of $114 million on our preferred stock during the Current Quarter, including $92 million of dividends in arrears that had been suspended throughout 2016. We did not pay dividends on our preferred stock in the Prior Quarter.
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Term Loan Facility
We have a secured five-year term loan facility in aggregate principal amount of $1.5 billion. Our obligations under the facility are unconditionally guaranteed on a joint and several basis by the same subsidiaries that guarantee our revolving credit facility, second lien notes and senior notes and are secured by first-priority liens on the same collateral securing our revolving credit facility (with a position in the collateral proceeds waterfall junior to the revolving credit facility). The term loan bears interest at a rate of London Interbank Offered Rate (LIBOR) plus 7.50% per annum, subject to a 1.00% LIBOR floor, or the Alternative Base Rate (ABR) plus 6.50% per annum, subject to a 2.00% ABR floor, at our option. The term loan matures in August 2021 and voluntary prepayments are subject to a make-whole premium prior to the second anniversary of the closing of the term loan, a premium to par of 4.25% from the second anniversary until but excluding the third anniversary, a premium to par of 2.125% from the third anniversary until but excluding the fourth anniversary and at par beginning on the fourth anniversary. The term loan may be subject to mandatory prepayments and offers to purchase with net cash proceeds of certain issuances of debt, certain asset sales and other dispositions of collateral and upon a change of control. 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 the term loan facility.
Revolving Credit Facility
We have a $4.0 billion senior secured revolving credit facility (currently subject to a $3.8 billion borrowing base) that matures in December 2019. As of March 31, 2017, we had no outstanding borrowings under the revolving credit facility and had used $697 million of the revolving credit facility for various letters of credit (including the $461 million supersedeas bond with respect to the 2019 Notes litigation). See Liquidity Overview above for additional information on our collateral postings. Borrowings under the facility bear interest at a variable rate. We are required to secure our obligations under the facility with liens on certain of our oil and natural gas properties, with the liens to be released upon the satisfaction of specific conditions. The applicable interest rates under the facility fluctuate based on the percentage of the borrowing base used. In 2016, we amended our revolving credit facility to provide covenant relief and affirm our $4.0 billion borrowing base. Our borrowing base may be reduced if we dispose of a certain percentage of the value of the collateral securing the facility. As a result of certain asset sales and certain other sales of collateral since the date of the most recent amendment, our borrowing base was reduced to $3.8 billion in October 2016. 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 the terms of the revolving credit facility, as amended. As of March 31, 2017, our interest coverage ratio was approximately 1.54 to 1.0, and we were in compliance with all applicable financial covenants under the credit agreement.
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 which allows us to reduce any letters of credit posted as security with those counterparties. In addition, with other counterparties we enter into bilateral hedging agreements. The counterparties’ and our obligations under certain of 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.
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Senior Note Obligations
Our senior note obligations consisted of the following as of March 31, 2017:

|  | March 31, 2017
|  | Principal Amount |  | Carrying Amount
|  | ($ in millions)
7.25% senior notes due 2018 |  | $ | 46 |  |  | $ | 46 |
Floating rate senior notes due 2019 |  | 380 |  |  | 380 |
6.625% senior notes due 2020 |  | 572 |  |  | 572 |
6.875% senior notes due 2020 |  | 279 |  |  | 279 |
6.125% senior notes due 2021 |  | 550 |  |  | 550 |
5.375% senior notes due 2021 |  | 270 |  |  | 270 |
4.875% senior notes due 2022 |  | 451 |  |  | 451 |
8.00% senior secured second lien notes due 2022(a) |  | 2,419 |  |  | 3,368 |
5.75% senior notes due 2023 |  | 338 |  |  | 338 |
8.00% senior notes due 2025 |  | 1,000 |  |  | 1,000 |
5.5% convertible senior notes due 2026(b)(c) |  | 1,250 |  |  | 818 |
2.75% contingent convertible senior notes due 2035(d) |  | 2 |  |  | 2 |
2.5% contingent convertible senior notes due 2037(c)(d) |  | 15 |  |  | 15 |
2.25% contingent convertible senior notes due 2038(c)(d) |  | 9 |  |  | 8 |
Debt issuance costs |  | — |  |  | (38 | )
Discount on senior notes |  | — |  |  | (16 | )
Interest rate derivatives(e) |  | — |  |  | 3 |
Total senior notes, net |  | 7,581 |  |  | 8,046 |
Less current maturities of senior notes, net(f) |  | (15 | ) |  | (15 | )
Total long-term senior notes, net |  | $ | 7,566 |  |  | $ | 8,031 |

___________________________________________

(a) | The carrying amount as of March 31, 2017, includes a premium of $949 million associated with a troubled debt restructuring. The premium is being amortized based on an effective yield method.

(b) | The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash, common stock or a combination of cash and common stock, at our election. The holders of our convertible senior notes may require us to repurchase the principal amount of the notes upon certain fundamental changes.

(c) | The carrying amount as of March 31, 2017, is reflected net of a discount associated with the equity component of our convertible and contingent convertible senior notes of $433 million.

(d) | The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash and, if applicable, shares of our common stock using a net share settlement process. We may redeem our 2.75% Contingent Convertible Senior Notes due 2035 at any time. The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date and upon certain fundamental changes. The first put date, for the 2.5% Contingent Convertible Senior Notes due 2037 (the 2037 Notes), is May 15, 2017. As required by the terms of the indenture for the 2037 Notes, on March 30, 2017, we issued a notice to the holders of the 2037 Notes allowing each holder an opportunity to require us to repurchase some or all of the notes on May 15, 2017. As a result, we may be required to repurchase some or all of the 2037 Notes outstanding on May 15, 2017. Beginning May 15, 2017, we may redeem any 2037 Notes that have not been put to us and repurchased. The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash and, if applicable, shares of our common stock using a net share settlement process.

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(e) | See Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for discussion related to these instruments.

(f) | As of March 31, 2017, current maturities of long-term debt, net include our 2037 Notes. As discussed in footnote (d) above and in Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of this report, the holders of our 2037 Notes could exercise their individual demand repurchase rights on May 15, 2017, which would require us to repurchase all or a portion of the principal amount of the notes.

For further discussion and details regarding our senior notes and convertible senior notes, see Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report.
Credit Risk
Derivative instruments that enable us to manage our exposure to oil, natural gas and NGL prices, as well as to foreign currency volatility, expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment grade 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 March 31, 2017, our oil, natural gas and NGL derivative instruments were spread among 10 counterparties. Additionally, the counterparties under our commodity hedging arrangements are required to secure their obligations in excess of defined thresholds.
Our accounts receivable are primarily from purchasers of oil, natural gas and NGL ($680 million as of March 31, 2017) and exploration and production companies that own interests in properties we operate ($177 million as of March 31, 2017). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parent guarantees for receivables from parties that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During the Current Quarter and the Prior Quarter, we recognized nominal amounts of bad debt expense related to potentially uncollectible receivables.
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 March 31, 2017, these arrangements and transactions included (i) operating lease agreements, (ii) volumetric production payments (VPPs) (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.
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Results of Operations – Three Months Ended March 31, 2017 vs March 31, 2016
General. For the Current Quarter, Chesapeake had net income of $141 million, or $0.08 per diluted common share, on total revenues of $2.753 billion. This compares to a net loss of $1.068 billion, or $1.66 per diluted common share, on total revenues of $1.953 billion for the Prior Quarter. The increase in net income in the Current Quarter is attributable to an increase in the average realized prices we received for oil, natural gas and NGL production, partially offset by charges for terminating certain natural gas and oil transportation commitments. See Impairments of Fixed Assets and Other below. The net loss in the Prior Quarter was primarily driven by non-cash impairments of oil and natural gas properties. See Impairment of Oil and Natural Gas Properties below.
Oil, Natural Gas and NGL Sales. During the Current Quarter, oil, natural gas and NGL sales were $1.469 billion compared to $993 million in the Prior Quarter. In the Current Quarter, Chesapeake sold 48 mmboe for $1.147 billion at a weighted average price of $24.13 per boe (excluding the effect of derivatives), compared to 61 mmboe sold in the Prior Quarter for $812 million at a weighted average price of $13.28 per boe (excluding the effect of derivatives). The increase in the price received per boe in the Current Quarter compared to the Prior Quarter resulted in a $516 million increase in revenues, and decreased sales volumes resulted in a $181 million decrease in revenues, for a total increase in revenues of $335 million (excluding the effect of derivatives).
For the Current Quarter, our average price received per barrel of oil (excluding the effect of derivatives) was $50.24, compared to $29.34 in the Prior Quarter. Natural gas prices received per mcf (excluding the effect of derivatives) were $3.10 and $1.75 in the Current Quarter and the Prior Quarter, respectively. NGL prices received per barrel (excluding the effect of derivatives) were $23.78 and $11.44 in the Current Quarter and the Prior Quarter, respectively.
Gains from our oil, natural gas and NGL derivatives resulted in a net increase in oil, natural gas and NGL revenues of $322 million in the Current Quarter and a net increase of $181 million in the Prior Quarter, respectively. See Item 3. Quantitative and Qualitative Disclosures About Market Risk in Part I of this report for a listing of all of our derivative instruments as of March 31, 2017.
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 result in an increase or decrease in Current Quarter revenues and cash flows of approximately $8 million and $7 million, respectively, an increase or decrease of $0.10 per mcf of natural gas sold would result in an increase or decrease in Current Quarter revenues and cash flows of approximately $21 million, and an increase or decrease of $1.00 per barrel of NGL sold would result in an increase or decrease in Current Quarter revenues and cash flows of $5 million.
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The following tables show production and average sales prices received by our operating divisions for the Current Quarter and the Prior Quarter:

|  | Three Months Ended March 31, 2017
|  | Oil |  | Natural Gas |  | NGL |  | Total
|  | (mmbbl) |  | ($/bbl)(a) |  | (bcf) |  | ($/mcf)(a) |  | (mmbbl) |  | ($/bbl)(a) |  | (mmboe) |  | % |  | ($/boe)(a)
Marcellus |  | — |  |  | — |  |  | 79 |  |  | 2.97 |  |  | — |  |  | — |  |  | 13 |  |  | 27 |  |  | 17.83 |
Haynesville |  | — |  |  | — |  |  | 65 |  |  | 2.99 |  |  | — |  |  | — |  |  | 11 |  |  | 23 |  |  | 17.95 |
Eagle Ford |  | 5 |  |  | 50.90 |  |  | 12 |  |  | 3.40 |  |  | 2 |  |  | 21.38 |  |  | 9 |  |  | 18 |  |  | 38.52 |
Utica |  | 1 |  |  | 45.41 |  |  | 34 |  |  | 3.49 |  |  | 2 |  |  | 25.75 |  |  | 9 |  |  | 19 |  |  | 24.16 |
Mid-Continent |  | 1 |  |  | 50.35 |  |  | 18 |  |  | 3.01 |  |  | 1 |  |  | 22.83 |  |  | 5 |  |  | 11 |  |  | 27.18 |
Powder River Basin |  | 1 |  |  | 49.69 |  |  | 3 |  |  | 3.33 |  |  | — |  |  | — |  |  | 1 |  |  | 2 |  |  | 32.67 |
Other(b) |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Total |  | 8 |  |  | 50.24 |  |  | 211 |  |  | 3.10 |  |  | 5 |  |  | 23.78 |  |  | 48 |  |  | 100 | % |  | 24.13 |
|  | Three Months Ended March 31, 2016
|  | Oil |  | Natural Gas |  | NGL |  | Total
|  | (mmbbl) |  | ($/bbl)(a) |  | (bcf) |  | ($/mcf)(a) |  | (mmbbl) |  | ($/bbl)(a) |  | (mmboe) |  | % |  | ($/boe)(a)
Marcellus |  | — |  |  | — |  |  | 78 |  |  | 1.43 |  |  | — |  |  | — |  |  | 13 |  |  | 21 |  |  | 8.59 |
Haynesville |  | — |  |  | — |  |  | 61 |  |  | 1.86 |  |  | — |  |  | — |  |  | 10 |  |  | 17 |  |  | 11.18 |
Eagle Ford |  | 5 |  |  | 30.01 |  |  | 12 |  |  | 2.12 |  |  | 1 |  |  | 10.79 |  |  | 8 |  |  | 14 |  |  | 22.32 |
Utica |  | 1 |  |  | 24.36 |  |  | 48 |  |  | 1.99 |  |  | 3 |  |  | 12.53 |  |  | 12 |  |  | 21 |  |  | 13.51 |
Mid-Continent |  | 2 |  |  | 30.88 |  |  | 32 |  |  | 1.79 |  |  | 2 |  |  | 9.98 |  |  | 9 |  |  | 14 |  |  | 14.85 |
Powder River Basin |  | 1 |  |  | 31.10 |  |  | 4 |  |  | 2.06 |  |  | — |  |  | — |  |  | 2 |  |  | 2 |  |  | 20.56 |
Other(b) |  | — |  |  | — |  |  | 41 |  |  | 1.76 |  |  | — |  |  | — |  |  | 7 |  |  | 11 |  |  | 10.49 |
Total |  | 9 |  |  | 29.34 |  |  | 276 |  |  | 1.75 |  |  | 6 |  |  | 11.44 |  |  | 61 |  |  | 100 | % |  | 13.28 |

___________________________________________

(a) | Average sales prices exclude gains (losses) on derivatives.

(b) | Includes Central Texas and Devonian Shale.

Our average daily production of 528 mboe for the Current Quarter consisted of approximately 84 mbbls of oil (16% on an oil equivalent basis), approximately 2.3 bcf of natural gas (74% on an oil equivalent basis) and approximately 54 mbbls of NGL (10% on an oil equivalent basis). Oil production decreased by 14%, natural gas production decreased by 24% and NGL production decreased by 25% year over year primarily as a result of the sale of certain of our Barnett and Mid-Continent assets in 2016 as well as a significant reduction in drilling and completion activity in 2016.
Excluding the impact of derivatives, our percentage of revenues from oil, natural gas and NGL is shown in the following table:

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
Oil |  | 33 |  |  | 31 |
Natural gas |  | 57 |  |  | 60 |
NGL |  | 10 |  |  | 9 |
Total |  | 100 | % |  | 100 | %

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Marketing, Gathering and Compression Revenues and Expenses. Marketing, gathering and compression revenues consist of third-party revenues as well as fair value adjustments on our supply contract derivatives (see Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for additional information on our supply contract derivatives). Expenses related to our marketing, gathering and compression operations consist of third-party expenses and exclude depreciation and amortization, general and administrative expenses, impairments of fixed assets and other, net gains or losses on sales of fixed assets and interest expense. See Depreciation and Amortization of Other Assets below for the depreciation and amortization recorded on our marketing, gathering and compression assets. We recognized $1.284 billion in marketing, gathering and compression revenues in the Current Quarter with corresponding expenses of $1.328 billion, for a net loss of $44 million. This compares to revenues of $960 million, of which $20 million related to unrealized gains on the fair value of our supply contract derivative, with corresponding expenses of $942 million, for a net margin of $18 million in the Prior Quarter. Revenues and expenses increased in the Current Quarter compared to the Prior Quarter primarily as a result of higher oil, natural gas and NGL prices paid and received in our marketing operations. The margin decrease in the Current Quarter as compared to the Prior Quarter was primarily the result of an unrealized gain on the fair value adjustment on our supply contract derivatives in the Prior Quarter and the sale of a significant portion of our gathering and compression assets, concurrently with the associated upstream assets. Additionally, the Current Quarter includes losses on certain transportation contracts with third parties associated with assets divested in the fourth quarter of 2016.
Oil, Natural Gas and NGL Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $135 million in the Current Quarter, compared to $206 million in the Prior Quarter. On a unit-of-production basis, production expenses were $2.84 per boe in the Current Quarter compared to $3.36 per boe in the Prior Quarter. The absolute and per unit decrease in the Current Quarter was the result of operating efficiencies across most of our operating areas, as well as lower production volumes due to the sale of certain oil and natural gas properties in 2016. Production expenses in the Current Quarter and the Prior Quarter included approximately $6 million and $13 million, or $0.12 and $0.21 per boe, respectively, associated with VPP production volumes. In connection with certain 2016 divestitures, we purchased the remaining oil and natural gas interests previously sold in connection with five of our VPPs, and a majority of these repurchased oil and natural gas interests were subsequently sold. 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.
Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses. Oil, natural gas and NGL gathering, processing and transportation expenses were $355 million in the Current Quarter compared to $482 million in the Prior Quarter. On a unit-of-production basis, gathering, processing and transportation expenses were $7.47 per boe in the Current Quarter compared to $7.88 per boe in the Prior Quarter. The absolute and per unit decrease primarily related to divestitures in 2016. A summary of oil, natural gas and NGL gathering, processing and transportation expenses by product is shown below.

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
Oil ($ per bbl) |  | $ | 3.85 |  |  | $ | 3.29 |
Natural gas ($ per mcf) |  | $ | 1.35 |  |  | $ | 1.46 |
NGL ($ per bbl) |  | $ | 8.47 |  |  | $ | 7.59 |

Production Taxes. Production taxes were $22 million in the Current Quarter compared to $18 million in the Prior Quarter. On a unit-of-production basis, production taxes were $0.47 per boe in the Current Quarter compared to $0.30 per boe in the Prior Quarter. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil, natural gas and NGL prices are higher. The absolute and per unit increase in production taxes in the Current Quarter was primarily due to higher prices received for our oil, natural gas and NGL production. Production taxes in both the Current Quarter and the Prior Quarter included approximately $1 million, or $0.02 per boe, associated with VPP production volumes.
General and Administrative Expenses. General and administrative expenses were $65 million in the Current Quarter and $48 million in the Prior Quarter, or $1.35 and $0.79 per boe, respectively. The absolute and per unit expense increase in the Current Quarter was primarily due to less overhead reflected as oil, natural gas and NGL production expenses, as well as less overhead billed to third party working interest owners, resulting from certain divestitures in 2016.
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Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, drilling and completion activities are capitalized. We capitalize internal costs that can be directly identified with the acquisition of leasehold, as well as drilling and completion activities, and do not include any costs related to production, general corporate overhead or similar activities. We capitalized $36 million and $37 million of internal costs in the Current Quarter and the Prior Quarter, respectively, directly related to our leasehold acquisition and drilling and completion efforts.
Provision for Legal Contingencies. In the Current Quarter and the Prior Quarter, we recorded income of $2 million and expense of $33 million, respectively, for legal contingencies. Both the Current Quarter and the Prior Quarter provision consists of adjustments for loss contingencies primarily related to royalty claims. See Note 4 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of royalty claims.
Oil, Natural Gas and NGL Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (DD&A) of oil, natural gas and NGL properties was $197 million and $263 million in the Current Quarter and the Prior Quarter, respectively. The average DD&A rate per boe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $4.15 and $4.30 in the Current Quarter and the Prior Quarter, respectively. The absolute and per unit decrease in the Current Quarter was the result of a lower amortization base, which is due to the 2016 impairments of our oil and natural gas properties.
Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $21 million in the Current Quarter compared to $29 million in the Prior Quarter. On a unit-of-production basis, depreciation and amortization of other assets was $0.44 per boe in the Current Quarter compared to $0.48 per boe in the Prior Quarter. Property and equipment costs are depreciated on a straight-line basis over the estimated useful lives of the assets. The following table shows depreciation expense by asset class for the Current Quarter and the Prior Quarter and the estimated useful lives of these assets.

|  | Three Months Ended March 31, |  | Estimated Useful Life
|  | 2017 |  | 2016 |
|  | ($ in millions) |  | (in years)
Buildings and improvements |  | $ | 9 |  |  | $ | 10 |  |  | 10 – 39
Natural gas compressors(a) |  | 4 |  |  | 8 |  |  | 3 – 20
Computers and office equipment |  | 5 |  |  | 4 |  |  | 3 – 7
Vehicles |  | 1 |  |  | 1 |  |  | 0 – 7
Natural gas gathering systems and treating plants(a) |  | — |  |  | 3 |  |  | 20
Other |  | 2 |  |  | 3 |  |  | 2 – 20
Total depreciation and amortization of other assets |  | $ | 21 |  |  | $ | 29 |  |  |

___________________________________________

(a) | Included in our marketing, gathering and compression operating segment.

Impairment of Oil and Natural Gas Properties. Our oil and natural gas properties are subject to quarterly full cost ceiling tests. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed a ceiling amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In the Current Quarter, capitalized costs of oil and natural gas properties did not exceed the ceiling. For the Prior Quarter, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment of the carrying value of our oil and natural gas properties of $997 million.
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Impairments of Fixed Assets and Other. In the Current Quarter and the Prior Quarter, we recognized $391 million and $38 million, respectively, of fixed asset impairment losses and other charges. In the Current Quarter, we paid $290 million to assign an oil transportation agreement to a third party. In addition, we terminated future natural gas transportation commitments related to divested assets for a cash payment of $103 million. The Prior Quarter amount primarily related to impairments of certain of our buildings, land and compressors as well as charges incurred for terminating drilling contracts as a result of the decline in oil and natural gas prices.
Net (Gains) Losses on Sales of Fixed Assets. In the Current Quarter, net losses on sales of fixed assets were a nominal amount compared to net gains of $4 million in the Prior Quarter. The Prior Quarter amounts primarily related to the sale of buildings, land and other property and equipment.
Interest Expense. Interest expense was $95 million in the Current Quarter compared to $62 million in the Prior Quarter as follows:

|  | Three Months Ended March 31,
|  | 2017 |  | 2016
|  | ($ in millions)
Interest expense on senior notes |  | $ | 136 |  |  | $ | 157 |
Interest expense on term loan |  | 32 |  |  | — |
Amortization of loan discount, issuance costs and other |  | 9 |  |  | 10 |
Amortization of premium associated with troubled debt restructuring |  | (41 | ) |  | (42 | )
Interest expense on revolving credit facilities |  | 9 |  |  | 5 |
Realized gains on interest rate derivatives(a) |  | (1 | ) |  | (3 | )
Unrealized (gains) losses on interest rate derivatives(b) |  | 2 |  |  | 3 |
Capitalized interest |  | (51 | ) |  | (68 | )
Total interest expense |  | $ | 95 |  |  | $ | 62 |
Average senior notes borrowings |  | $ | 7,689 |  |  | $ | 9,567 |
Average credit facilities borrowings |  | $ | — |  |  | $ | 69 |
Average term loan borrowings |  | $ | 1,500 |  |  | $ | — |

___________________________________________

(a) | Includes settlements related to the interest accrual for the period and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item.

(b) | Includes changes in the fair value of interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.

The decrease in interest expense on senior notes is due to the decrease in the average outstanding principal amount of senior notes. The decrease in capitalized interest resulted from lower average balances of unproved oil and natural gas properties, the primary asset on which interest is capitalized. Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $1.97 per boe in the Current Quarter compared to $0.98 per boe in the Prior Quarter.
Loss on Sale of Investment. In the Prior Quarter, we sold certain of our mineral interests and assigned our partnership interest in Mineral Acquisition Company I, L.P. to KKR Royalty Aggregator LLC. As a result of the transaction, we wrote off our equity investment and recognized a $10 million loss.
Gains (Losses) on Purchases or Exchanges of Debt. In the Current Quarter, we retired $908 million principal amount of our outstanding senior notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $982 million, which included the maturity of our 6.25% Euro-denominated Senior Notes due 2017 and the corresponding cross currency swap. We recorded an aggregate loss of $7 million associated with the repurchases and tender offers.
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In the Prior Quarter, we retired $558 million principal amount of our outstanding senior notes and contingent convertible senior notes through purchases in the open market, tender offers or repayment upon maturity for $472 million. Additionally, we privately negotiated an exchange of approximately $105 million principal amount of our outstanding senior notes and contingent convertible senior notes for 17,255,347 common shares. We recorded an aggregate gain of approximately $100 million associated with the repurchases and exchanges.
Other Income. Other income was $3 million in both the Current Quarter and the Prior Quarter. The Current Quarter other income consisted primarily of miscellaneous income. The Prior Quarter other income consisted of $1 million of interest income and $2 million of miscellaneous income.
Income Tax Expense (Benefit). Chesapeake recorded an income tax expense of $1 million in the Current Quarter. Our effective income tax rate was 0.7% in the Current Quarter and 0.0% in the Prior Quarter. The increase in the effective income tax rate from the Prior Quarter to the Current Quarter is primarily due to the accrual of current state income tax expenses in the Current Quarter. Further, our effective tax rate can fluctuate as a result of the impact of state income taxes and permanent differences. See Note 12 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 (benefit).
Net Income Attributable to Noncontrolling Interests. Chesapeake recorded net income attributable to noncontrolling interests of $1 million and a nominal amount in the Current Quarter and the Prior Quarter, respectively. In both quarters, activity was attributable to the Chesapeake Granite Wash Trust.
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 give our current expectations or forecasts of future events. They include expected oil, natural gas and NGL production and future expenses, estimated operating costs, assumptions regarding future oil, natural gas and NGL prices, planned drilling activity, estimates of future drilling and completion and other capital expenditures (including the use of joint venture drilling carries), potential future write-downs of our oil and natural gas assets, anticipated sales, and the adequacy of our provisions for legal contingencies, as well as statements concerning anticipated cash flow and liquidity, ability to fund planned capital expenditures and debt service requirements and comply with financial maintenance covenants, meet contractual cash commitments to third parties, debt repurchases, operating and capital efficiencies, business strategy, the effect of our remediation plan for a material weakness, and other plans and objectives for future operations. Disclosures concerning the fair values of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility.
Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results are described under Risk Factors in Item 1A of our annual report on Form 10-K for the year ended December 31, 2016 (2016 Form 10-K) and include:

• | the volatility of oil, natural gas and NGL prices;

• | 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;

• | our credit rating requiring us to post more collateral under certain commercial arrangements;

• | write-downs of our oil and natural gas asset carrying values due to low commodity prices;

• | our ability to replace reserves and sustain production;

• | 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 generate profits or achieve targeted results in drilling and well operations;

• | leasehold terms expiring before production can be established;

• | commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales;

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• | the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations;

• | adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims;

• | charges incurred in response to market conditions and in connection with our ongoing actions to reduce financial leverage and complexity;

• | drilling and operating risks and resulting liabilities;

• | effects of environmental protection laws and regulation on our business;

• | legislative and regulatory initiatives further regulating hydraulic fracturing;

• | our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used;

• | impacts of potential legislative and regulatory actions addressing climate change;

• | federal and state tax proposals affecting our industry;

• | potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations;

• | competition in the oil and gas exploration and production industry;

• | a deterioration in general economic, business or industry conditions;

• | negative public perceptions of our industry;

• | limited control over properties we do not operate;

• | pipeline and gathering system capacity constraints and transportation interruptions;

• | terrorist activities and/or cyber-attacks adversely impacting our operations;

• | potential challenges by SSE’s former creditors of our spin-off of in connection with SSE’s recently completed bankruptcy under Chapter 11 of the U.S. Bankruptcy Code;

• | an interruption in operations at our headquarters due to a catastrophic event;

• | the continuation of suspended dividend payments on our common stock;

• | the effectiveness of our remediation plan for a material weakness;

• | certain anti-takeover provisions that affect shareholder rights; and

• | our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means.

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 except as required by applicable law. We urge you to carefully review and consider the disclosures made 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. These instruments allow us to predict with greater certainty the effective prices to be received for our share of production. 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 and natural gas 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.
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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 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.
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 of related production based on the terms 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 Chesapeake 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 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 March 31, 2017, our oil, natural gas and NGL derivative instruments consisted of the following:

• | Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.

• | Options: Chesapeake sells, and occasionally buys, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty the excess on sold call options, and Chesapeake receives the excess on bought call options. If the market price settles below the fixed price of the call options, no payment is due from either party.

• | 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, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call strike prices, no payments are due from either party.

• | Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. Chesapeake receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity.

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As of March 31, 2017, 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 |  |  | $ | 50.28 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (25 | )
Long-term |  | 1 |  |  | $ | 51.43 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | (1 | )
Call Options (sold): |  |  |  |  |  |  |  |  |  |  |  |
Short-term |  | 4 |  |  | $ | — |  |  | $ | 83.50 |  |  | $ | — |  |  | $ | — |  |  | — |
Total Oil |  | $ | (26 | )
|  | (tbtu) |  | ($ per mmbtu) |  |
Natural Gas: |  |  |  |  |  |  |  |  |  |  |  |
Swaps: |  |  |  |  |  |  |  |  |  |  |  |
Short-term |  | 548 |  |  | $ | 3.10 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (126 | )
Long-term |  | 74 |  |  | $ | 2.88 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | — |
Collars: |  |  |  |  |  |  |  |  |  |  |  |
Short-term |  | 12 |  |  | $ | — |  |  | $ | 3.25 |  |  | $ | 3.00 |  |  | $ | — |  |  | (4 | )
Long-term |  | 36 |  |  | $ | — |  |  | $ | 3.25 |  |  | $ | 3.00 |  |  | $ | — |  |  | 7 |
Call Options (sold): |  |  |  |  |  |  |  |  |  |  |  |
Short-term |  | 42 |  |  | $ | — |  |  | $ | 9.77 |  |  | $ | — |  |  | $ | — |  |  | — |
Long-term |  | 60 |  |  | $ | — |  |  | $ | 12.00 |  |  | $ | — |  |  | $ | — |  |  | — |
Basis Protection Swaps: |  |  |  |  |  |  |  |  |  |  |  |
Short-term |  | 18 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (0.48 | ) |  | (2 | )
Long-term |  | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (1.03 | ) |  | — |
Total Natural Gas |  | $ | (125 | )
|  | (mmgal) |  | ($ per mgal) |  |
NGL: |  |  |  |  |  |  |  |  |  |  |  |
Ethane Swaps: |  |  |  |  |  |  |  |  |  |  |  |
Short-term |  | 27 |  |  | $ | 0.28 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 1 |
Total NGL |  | $ | 1 |
Total Oil, Natural Gas and NGL |  | $ | (150 | )

In addition to the open derivative positions disclosed above, as of March 31, 2017, we had $18 million of net derivative losses related to settled contracts for future production periods that will be recorded within oil, natural gas and NGL sales 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 of related production, based on the terms specified in the original contract as noted below.

|  | March 31, 2017
|  | ($ in millions)
Short-term |  | $ | 56 |
Long-term |  | (74 | )
Total |  | $ | (18 | )

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The table below reconciles the changes in fair value of our oil and natural gas derivatives during the Current Quarter. Of the $150 million fair value liability as of March 31, 2017, a $156 million liability relates to contracts maturing in the next 12 months and a $6 million asset relates to contracts maturing after 12 months. All open derivative instruments as of March 31, 2017 are expected to mature by December 31, 2022.

|  | March 31, 2017
|  | ($ in millions)
Fair value of contracts outstanding, as of January 1, 2017 |  | $ | (504 | )
Change in fair value of contracts |  | 332 |
Contracts realized or otherwise settled |  | 22 |
Fair value of contracts outstanding, as of March 31, 2017 |  | $ | (150 | )

The change in oil and natural gas prices during the Current Quarter decreased the liability related to our derivative instruments by $332 million. This unrealized gain is recorded in oil, natural gas and NGL sales. We settled contracts in the Current Quarter that were in a liability position for $22 million. Realized gains and losses will be recorded in oil, natural gas and NGL sales in the month of related production.
Interest Rate Derivatives
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. As of March 31, 2017, we had total debt of $9.081 billion, including $7.201 billion of fixed rate debt at interest rates averaging 6.85% and $1.880 billion of floating rate debt at an interest rate of 7.65%.

| Years of Maturity |  |
| 2017 |  | 2018 |  | 2019 |  | 2020 |  | 2021 |  | Thereafter |  | Total
| ($ in millions)
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |
Debt – fixed rate(a) | $ | 15 |  |  | $ | 55 |  |  | $ | — |  |  | $ | 853 |  |  | $ | 820 |  |  | $ | 5,458 |  |  | $ | 7,201 |
Average interest rate | 2.50 | % |  | 6.45 | % |  | — | % |  | 6.70 | % |  | 5.88 | % |  | 7.03 | % |  | 6.85 | %
Debt – variable rate | $ | — |  |  | $ | — |  |  | $ | 380 |  |  | $ | — |  |  | $ | 1,500 |  |  | $ | — |  |  | $ | 1,880 |
Average interest rate | — | % |  | — | % |  | 4.27 | % |  | — | % |  | 8.50 | % |  | — | % |  | 7.65 | %

___________________________________________

(a) | This amount does not include the premium, discount and deferred financing costs included in debt of $440 million and interest rate derivatives of $3 million.

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, term loan 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.
From time to time, we enter into interest rate derivatives, including fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes and floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our revolving credit facility borrowings. As of March 31, 2017, there were no interest rate derivatives outstanding.
As of March 31, 2017, we had $11 million of net gains related to settled 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.
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Foreign Currency Derivatives
We were party to cross currency swaps to mitigate our exposure to foreign currency exchange rate fluctuations. During the Current Quarter, both our 6.25% Euro-denominated Senior Notes due 2017 and cross currency swaps for the same principal amount matured. Upon maturity of the notes, t he counterparties paid us €246 million and we paid the counterparties $327 million. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. The swaps were designated as cash flow hedges and, because they were entirely effective in having eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates, changes in their fair value did not impact earnings. The fair values of the cross currency swaps were recorded on the condensed consolidated balance sheet as a liability of $73 million as of December 31, 2016.

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 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 Chesapeake’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of March 31, 2017, because of the material weakness in our internal control over financial reporting described in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8 of Part II of our Annual Report on Form 10-K for the year ended December 31, 2016.
Remediation Plan for the Material Weakness
Our management is actively engaged in the planning for, and implementation of, remediation efforts to address the material weakness identified. Specifically, our management is in the process of implementing a control related to reviewing the configuration of the basis price differential calculations, including a control activity to verify any subsequent changes are appropriately reviewed and that the interface control is designed to validate the data at an appropriately disaggregated level. Our management believes that these actions will remediate the material weakness in internal control over financial reporting.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended March 31, 2017, which materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION

ITEM 1. | Legal Proceedings

Litigation and Regulatory Proceedings
The Company is involved in a number of litigation and regulatory proceedings (including those described below). Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is currently indeterminate. See Note 4 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings.
Regulatory and Related Proceedings. The Company has received, from the U.S. Department of Justice (DOJ) and certain state governmental agencies and authorities, subpoenas and demands for documents, information and testimony in connection with investigations into possible violations of federal and state antitrust laws relating to our purchase and lease of oil and natural gas rights in various states. The Company also has received DOJ, U.S. Postal Service and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake has engaged in discussions with the DOJ, U.S. Postal Service and state agency representatives and continues to respond to such subpoenas and demands.
In addition, the Company received a DOJ subpoena and a voluntary document request from the SEC seeking information on our accounting methodology for the acquisition and classification of oil and natural gas properties and related matters. Chesapeake has engaged in discussions with the DOJ and SEC about these matters. On October 4, 2016, a securities class action was filed in the U.S. District Court for the Western District of Oklahoma against the Company and certain current directors and officers of the Company alleging, among other things, violations of federal securities laws for purported misstatements in the Company’s SEC filings and other public disclosures regarding the Company’s accounting for the acquisition and classification of oil and natural gas properties. The lawsuit seeks certification as a class action, damages, attorneys’ fees and other costs.
Redemption of 2019 Notes. See Note 4 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a description of recent litigation regarding the redemption in May 2013 of our 6.775% Senior Notes due 2019 (the 2019 Notes).
Business Operations. Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL. Plaintiffs have varying royalty provisions in their respective leases. Oil and gas law varies from state to state, and royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations. The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defending lawsuits seeking damages with respect to royalty underpayment in various states, including, but not limited to, Texas, Pennsylvania, Ohio, Oklahoma, Kentucky, Louisiana and Arkansas. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The Company also has received DOJ, U.S. Postal Service and state subpoenas or information requests seeking information on the Company’s royalty payment practices.
Chesapeake is defending numerous lawsuits filed by individual royalty owners alleging royalty underpayment with respect to properties in Texas. These lawsuits, organized for pre-trial proceedings with respect to the Barnett Shale and Eagle Ford Shale, respectively, generally allege that Chesapeake underpaid royalties by making improper deductions, using incorrect production volumes and similar theories. Chesapeake expects that additional lawsuits will continue to be pursued and that new plaintiffs will file other lawsuits making similar allegations.
On December 9, 2015, the Commonwealth of Pennsylvania, by the Office of Attorney General, filed a lawsuit in the Bradford County Court of Common Pleas related to royalty underpayment and lease acquisition and accounting practices with respect to properties in Pennsylvania. The lawsuit, which primarily relates to the Marcellus Shale and Utica Shale, alleges that Chesapeake violated the Pennsylvania Unfair Trade Practices and Consumer Protection Law (UTPCPL) by making improper deductions and entering into arrangements with affiliates that resulted in underpayment
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of royalties. The lawsuit includes other UTPCPL claims and antitrust claims, including that a joint exploration agreement to which Chesapeake is a party established unlawful market allocation for the acquisition of leases. The lawsuit seeks statutory restitution, civil penalties and costs, as well as temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid and a permanent injunction from further violations of the UTPCPL. Chesapeake has filed preliminary objections to the most recently amended complaint.
Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the Company’s divestiture of substantially all of its midstream business and most of its gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and for an unlawful market allocation agreement for mineral rights. One of the cases includes claims of intentional interference with contractual relations and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources.
The Company is also defending lawsuits alleging various violations of the Sherman Antitrust Act and state antitrust laws. In 2016, putative class action lawsuits have been 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 the Company 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.
Environmental Proceedings
Our subsidiary Chesapeake Appalachia, LLC (CALLC) is engaged in discussions with the EPA, the U.S. Army Corps of Engineers and the Pennsylvania Department of Environmental Protection (PADEP) regarding potential violations of the permitting requirements of the federal Clean Water Act, the Pennsylvania Clean Streams Law and the Pennsylvania Dam Safety and Encroachments Act in connection with the placement of dredge and fill material during construction of certain sites in Pennsylvania. CALLC identified the potential violations in connection with an internal review of its facilities siting and construction processes and voluntarily reported them to the regulatory agencies. Resolution of the matter may result in monetary sanctions of more than $100,000.
On December 27, 2016, we received a Finding of Violation from the EPA alleging violations of the Clean Air Act at a number of locations in Ohio. We have exchanged information with the EPA and are engaged in discussions aimed at resolving the allegations. Resolution of the matter may result in monetary sanctions of more than $100,000.
On October 14, 2016, we were named as a defendant in a putative class action in the U.S. District Court for the Western District of Oklahoma, alleging that we and the other defendants have operated produced water disposal wells in a manner that has caused earthquakes. The proposed class would consist of property owners in a twenty-six county area of Oklahoma. The petition seeks, among other relief, reimbursement of insurance premiums and an award of damages for injury to real property.
On February 16, 2016, we were named as a defendant in a lawsuit brought in the U.S. District Court for the Western District of Oklahoma by the Sierra Club. The complaint alleged that we and the other defendants, all exploration and production companies, violated the federal Resource Conservation and Recovery Act by operating produced water disposal wells in a manner that has caused earthquakes. Plaintiffs sought a court order requiring substantial reduction of the amounts of produced water disposed of in such manner, the creation of an earthquake prediction center, and the reinforcement of purportedly vulnerable structures that could be impacted by earthquakes. Chesapeake and the other defendants filed Motions to Dismiss the Amended Complaint, which the Court granted on April 4, 2017.

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 2016 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.
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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 March 31, 2017:

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)
January 1, 2017 through January 31, 2017 |  | 270,782 |  |  | $ | 7.01 |  |  | — |  |  | $ | 1,000 |
February 1, 2017 through February 28, 2017 |  | 1,963 |  |  | $ | 5.45 |  |  | — |  |  | $ | 1,000 |
March 1, 2017 through March 31, 2017 |  | 1,183,177 |  |  | $ | 5.45 |  |  | — |  |  | $ | 1,000 |
Total |  | 1,455,922 |  |  | $ | 5.74 |  |  | — |  |  |

___________________________________________

(a) | Reflects the surrender to the Company of shares of common stock to pay withholding taxes in connection with the vesting of employee restricted stock. Also includes shares of common stock purchased on behalf of Chesapeake’s deferred compensation plan related to participant deferrals and Company matching contributions.

(b) | In December 2014, the Company’s Board of Directors authorized the repurchase of up to $1 billion in value of its common stock from time to time. The repurchase program does not have an expiration date. As of March 31, 2017, no repurchases had been made under the program.

ITEM 3. | Defaults Upon Senior Securities

Not applicable.

ITEM 4. | Mine Safety Disclosures

Not applicable.

ITEM 5. | Other Information

On May 3, 2017, Michael A. Johnson left the employment of the Company as Senior Vice President - Accounting, Controller and Chief Accounting Officer.

ITEM 6. | Exhibits

The exhibits listed below in the Index of Exhibits (following the signatures page) are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.
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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: May 4, 2017 | By: |  | /s/ ROBERT D. LAWLER
|  |  | Robert D. Lawler, President and Chief Executive Officer

Date: May 4, 2017 | By: |  | /s/ DOMENIC J. DELL’OSSO, JR.
|  |  | Domenic J. Dell’Osso, Jr. Executive Vice President and Chief Financial Officer

TABLE OF CONTENTS
INDEX OF EXHIBITS

|  |  |  | Incorporated by Reference |  | Filed or Furnished Herewith
Exhibit Number |  | Exhibit Description |  | Form |  | SEC File Number |  | Exhibit |  | Filing Date |
3.1.1 |  | Chesapeake’s Restated Certificate of Incorporation. |  | 10-Q |  | 001-13726 |  | 3.1.1 |  | 8/6/2014 |  |
3.1.2 |  | Certificate of Amendment to Restated Certificate of Incorporation |  | 8-K |  | 001-13726 |  | 3.1 |  | 5/20/2016 |  |
3.1.3 |  | Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2005B), as amended. |  | 10-Q |  | 001-13726 |  | 3.1.4 |  | 11/10/2008 |  |
3.1.4 |  | Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock, as amended. |  | 10-Q |  | 001-13726 |  | 3.1.6 |  | 8/11/2008 |  |
3.1.5 |  | Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock (Series A). |  | 8-K |  | 001-13726 |  | 3.2 |  | 5/20/2010 |  |
3.1.6 |  | Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock, as amended. |  | 10-Q |  | 001-13726 |  | 3.1.5 |  | 8/9/2010 |  |
3.2 |  | Chesapeake’s Amended and Restated Bylaws. |  | 8-K |  | 001-13726 |  | 3.2 |  | 6/19/2014 |  |
12 |  | Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends. |  |  |  |  |  |  |  |  |  | X
31.1 |  | Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  |  |  |  |  |  |  |  |  | X
31.2 |  | Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  |  |  |  |  |  |  |  |  | X
32.1 |  | Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |  |  |  |  |  |  |  |  |  | X
32.2 |  | Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |  |  |  |  |  |  |  |  |  | X
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